Closed-loop conveyance systems for well servicing

ABSTRACT

A closed-loop system is used to perform a variety of well services. The well services include well completion services, production and maintenance services, and enhanced recovery services. A closed-loop system to complete an oil and gas well is an automated system under computer control that executes a sequence of programmed steps, but those steps depend in part upon information obtained from at least one downhole sensor that is communicated to the surface to optimize and/or change the steps executed by the computer to complete the well. A tractor conveyor with a Retrieval Sub is a tractor deployer that may be used to deploy completion devices and other devices within the wellbore to perform well services. The tractor deployer may be operated from a wireline, or from an umbilical. The umbilical may be made from composite materials and it may be a neutrally buoyant in any well fluids present. The umbilical provides power and data communications downhole. The umbilical may also be coiled tubing possessing electrical conductors. Other conveyance systems are provided to deploy completion devices and other devices within the wellbore to perform well services. The closed-loop system may also be used to monitor and control production of hydrocarbons from the wellbore.

PRIORITY FROM U.S. PROVISIONAL PATENT APPLICATIONS

The present application claims priority from and the benefit of U.S.Provisional Patent Application No. 60/384,964, filed Jun. 3, 2002, thatis entitled “Umbilicals for Well Conveyance Systems and Additional SmartShuttles and Related Drilling Systems”, which is fully incorporatedherein by reference.

The present application claims priority from and the benefit of U.S.Provisional Patent Application No. 60/367,638, filed Mar. 26, 2002, thatis entitled “Smart Shuttle Systems and Drilling Systems”, which is fullyincorporated herein by reference.

The present application claims priority from and the benefit of U.S.Provisional Patent Application No. 60/353,457, filed Jan. 31, 2002,which is entitled “Additional Smart Shuttle Systems”, which is fullyincorporated herein by reference.

The present application also claims priority from and the benefit ofU.S. Provisional Patent Application No. 60/313,654, filed Aug. 19, 2001,that is entitled “Smart Shuttle Systems”, which is fully incorporatedherein by reference.

Priority from U.S. Patent Applications

The present application is a continuation-in-part (C.I.P.) applicationof application Ser. No. 09/487,197, filed Jan. 19, 2000, that isentitled “Closed-Loop System to Complete Oil and Gas Wells”, now U.S.Pat. No. 6,397,946, that issued on Jun. 4, 2002, which is fullyincorporated herein by reference.

Application Ser. No. 09/487,197 is corrected to be, by a Certificate ofCorrection, a continuation-in-part of application Ser. No. 09/295,808,filed Apr. 20, 1999, that is entitled “One Pass Drilling and Completionof Extended Reach Lateral Wellbores with Drill Bit Attached to DrillString to Produce Hydrocarbons from Offshore Platforms”, now U.S. Pat.No. 6,263,987, that issued on Jul. 24, 2001, which is fully incorporatedherein by reference.

Application Ser. No. 09/295,808 is a continuation-in-part of applicationSer. No. 08/708,396, filed Sep. 3, 1996, that is entitled “Method andApparatus for Cementing Drill Strings in Place for One Pass Drilling andCompletion of Oil and Gas Wells”, now U.S. Pat. No. 5,894,897, thatissued on Apr. 20, 1999, which is fully incorporated herein byreference.

Application Ser. No. 08/708,396 is a continuation-in-part of applicationSer. No. 08/323,152, filed Oct. 14, 1994, that is entitled “Method andApparatus for Cementing Drill Strings in Place for One Pass Drilling andCompletion of Oil and Gas Wells”, now U.S. Pat. No. 5,551,521, thatissued on Sep. 3, 1996, which is fully incorporated herein by reference.

Applicant claims priority from and the benefit of the above fourapplications having Ser. Nos. 09/487,197, 09/295,808, 08/708,396, and08/323,152.

Related Applications

The present application relates to application Ser. No. 09/375,479,filed Aug. 16, 1999, that is entitled “Smart Shuttles to Complete Oiland Gas Wells”, now U.S. Pat. No. 6,189,621, that issued on Feb. 20,2001, which is fully incorporated herein by reference.

The present application further relates to PCT Application Serial No.PCT/US00/22095, filed Aug. 9, 2000, that is entitled “Smart Shuttles toComplete Oil and Gas Wells”, which is fully incorporated herein byreference. This PCT Application corresponds to Ser. No. 09/375,479.

The present application also relates to application Ser. No. 09/294,077,filed Apr. 18, 1999, that is entitled “One Pass Drilling and Completionof Wellbores with Drill Bit Attached to Drill String to Make CasedWellbores to Produce Hydrocarbons”, now U.S. Pat. No. 6,158,531, thatissued on Dec. 12, 2000, which is fully incorporated herein byreference.

Related U.S. Disclosure Documents

This application further relates to disclosure in U.S. DisclosureDocument No. 362582, filed on Sep. 30, 1994, that is entitled ‘RE: Draftof U.S. Patent Application Entitled “Method and Apparatus for CementingDrill Strings in Place for One Pass Drilling and Completion of Oil andGas Wells”’, an entire copy of which is incorporated herein byreference.

This application further relates to disclosure in U.S. DisclosureDocument No. 445686, filed on Oct. 11, 1998, having the title that readsexactly as follows: ‘RE:—Invention Disclosure— entitled “William BanningVail III, Oct. 10, 1998”’, an entire copy of which is incorporatedherein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 451044, filed on Feb. 8, 1999, that is entitled ‘RE:—Invention Disclosure—“Drill Bit Having Monitors and ControlledActuators”’, an entire copy of which is incorporated herein byreference.

This application further relates to disclosure in U.S. DisclosureDocument No. 451292, filed on Feb. 10, 1999, that is entitled ‘RE:—Invention Disclosure—“Method and Apparatus to Guide Direction of RotaryDrill Bit” dated Feb. 9, 1999”’, an entire copy of which is incorporatedherein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 452648 filed on Mar. 5, 1999 that is entitled ‘RE:“—Invention Disclosure— Feb. 28, 1999 One-Trip-Down-Drilling InventionsEntirely Owned by William Banning Vail III”’, an entire copy of which isincorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 455731 filed on May 2, 1999 that is entitled ‘RE:—INVENTION DISCLOSURE— entitled “Summary of One-Trip-Down-DrillingInventions”, an entire copy of which is incorporated herein byreference.

This application further relates to disclosure in U.S. DisclosureDocument No. 458978 filed on Jul. 13, 1999 that is entitled in part “RE:—INVENTION DISCLOSURE MAILED JUL. 13, 1999”, an entire copy of which isincorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 459470 filed on Jul. 20, 1999 that is entitled in part ‘RE:—INVENTION DISCLOSURE ENTITLED “Different Methods and Apparatus to“Pump-down” . . . ”’, an entire copy of which is incorporated herein byreference.

This application further relates to disclosure in U.S. DisclosureDocument No. 462818 filed on Sep. 23, 1999 that is entitled in part“Directional Drilling of Oil and Gas Wells Provided by DownholeModulation of Mud Flow”, an entire copy of which is incorporated hereinby reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 465344 filed on Nov. 19, 1999 that is entitled in part“Smart Cricket Repeaters in Drilling Fluids for Wellbore CommunicationsWhile Drilling Oil and Gas Wells”, an entire copy of which isincorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 474370 filed on May 16, 2000 that is entitled in part“Casing Drilling with Standard MWD/LWD Drilling Assembly Latched intoCasing Having Releasable Standard Sized Drill Bit”, an entire copy ofwhich is incorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 475584 filed on Jun. 13, 2000 that is entitled in part“Lower Portion of Standard LWD/MWD Rotary Drill String with RotarySteering System and Rotary Drill Bit Latched into ID of Larger CasingHaving Undercutter to Drill Oil and Gas Wells Whereby the Lower Portionis Retrieved upon Completion of the Wellbore”, an entire copy of whichis incorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 475681 filed on Jun. 17, 2000 that is entitled in part “ROVConveyed Smart Shuttle System Deployed by Workover Ship for Subsea WellCompletion and Subsea Well Servicing”, an entire copy of which isincorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 496050 filed on Jun. 25, 2001 that is entitled in part“SDCI Drilling and Completion Patents and Technology and SDCI SubseaRe-Entry Patents and Technology”, an entire copy of which isincorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 480550 filed on Oct. 2, 2000 that is entitled in part “NewDraft Figures for New Patent Applications”, an entire copy of which isincorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 493141 filed on May 2, 2001 that is entitled in part“Casing Boring Machine with Rotating Casing to Prevent Sticking Using aRotary Rig”, an entire copy of which is incorporated herein byreference.

This application further relates to disclosure in U.S. DisclosureDocument No. 492112 filed on Apr. 12, 2001 that is entitled in part“Smart Shuttles Conveyed Drilling Systems”, an entire copy of which isincorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 495112 filed on Jun. 11, 2001 that is entitled in part“Liner/Drainhole Drilling Machine”, an entire copy of which isincorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 494374 filed on May 26, 2001 that is entitled in part“Continuous Casting Boring Machine”, an entire copy of which isincorporated herein by reference.

This application further relates to disclosure in U.S. DisclosureDocument No. 495111 filed on Jun. 11, 2001 that is entitled in part“Synchronous Motor Injector System”, an entire copy of which isincorporated herein by reference.

And yet further, this application also relates to disclosure in U.S.Disclosure Document No. 497719 filed on Jul. 27, 2001 that is entitledin part “Many Uses for The Smart Shuttle™ and Well Locomotive”, anentire copy of which is incorporated herein by reference.

Various references are referred to in the above defined U.S. DisclosureDocuments. For the purposes herein, the term “reference cited inapplicant's U.S. Disclosure Documents” shall mean those particularreferences that have been explicitly listed and/or defined in any ofapplicant's above listed U.S. Disclosure Documents and/or in theattachments filed with those U.S. Disclosure Documents. Applicantexplicitly includes herein by reference entire copies of each and every“reference cited in applicant's U.S. Disclosure Documents”. Inparticular, applicant includes herein by reference entire copies of eachand every U.S. Patent cited in U.S. Disclosure Document No. 452648,including all its attachments, that was filed on Mar. 5, 1999. To bestknowledge of applicant, all copies of U.S. Patents that were orderedfrom commercial sources that were specified in the U.S. DisclosureDocuments are in the possession of applicant at the time of the filingof the application herein.

Applications for U.S. Trademarks have been filed in the USPTO forseveral terms used in this application. An application for the Trademark“Smart Shuttle™” was filed on Feb. 14, 2001 that is Serial No.76/213676, an entire copy of which is incorporated herein by reference.The “Smart Shuttle™” is also called the “Well Locomotive™”. Anapplication for the Trademark “Well Locomotive™” was filed on Feb. 20,2001 that is Serial Number 76/218211, an entire copy of which isincorporated herein by reference. An application for the Trademark of“Downhole Rig” was filed on Jun. 11, 2001 that is Serial Number76/274726, an entire copy of which is incorporated herein by reference.An application for the Trademark “Universal Completion Devices” wasfiled on Jul. 24, 2001 that is Serial Number 76/293175, an entire copyof which is incorporated herein by reference. An application for theTrademark “Downhole BOP” was filed on Aug. 17, 2001 that is SerialNumber 76/305201, an entire copy of which is incorporated herein byreference.

Accordingly, in view of the Trademark Applications, the term “smartshuttle” will be capitalized as “Smart Shuttle”; the term “welllocomotive” will be capitalized as “Well Locomotive”; the term“universal completion device” will be capitalized as “UniversalCompletion Device”; and the term “downhole bop” will be capitalized as“Downhole BOP”.

BACKGROUND OF THE INVENTION

1. Field of Invention

The fundamental field of the invention relates to apparatus and methodsof operation that substantially reduce the number of steps and thecomplexity to drill and complete oil and gas wells. Because of theextraordinary breadth of the fundamental field of the invention, thereare many related separate fields of the invention.

Accordingly, the field of invention relates to apparatus that uses thesteel drill string attached to a drilling bit during drilling operationsused to drill oil and gas wells for a second purpose as the casing thatis cemented in place during typical oil and gas well completions. Thefield of invention further relates to methods of operation of apparatusthat provides for the efficient installation of a cemented steel casedwell during one single pass down into the earth of the steel drillstring. The field of invention further relates to methods of operationof the apparatus that uses the typical mud passages already present in atypical drill bit, including any watercourses in a “regular bit”, or mudjets in a “jet bit”, that allow mud to circulate during typical drillingoperations for the second independent, and the distinctly separate,purpose of passing cement into the annulus between the casing and thewell while cementing the drill string into place during one singledrilling pass into the earth. The field of invention further relates toapparatus and methods of operation that provides the pumping of cementdown the drill string, through the mud passages in the drill bit, andinto the annulus between the formation and the drill string for thepurpose of cementing the drill string and the drill bit into placeduring one single drilling pass into the formation. The field ofinvention further relates to a one-way cement valve and related devicesinstalled near the drill bit of the drill string that allows the cementto set up efficiently while the drill string and drill bit are cementedinto place during one single drilling pass into the formation. The fieldof invention further relates to the use of a slurry material instead ofcement to complete wells during the one pass drilling of oil and gaswells, where the term “slurry material” may be any one, or more, of atleast the following substances: cement, gravel, water, “cement clinker”,a “cement and copolymer mixture”, a “blast furnace slag mixture”, and/orany mixture thereof; or any known substance that flows under sufficientpressure. The field of invention further relates to the use of slurrymaterials for the following type of generic well completions: open-holewell completions; typical cemented well completions having perforatedcasings; gravel well completions having perforated casings; and for anyother related well completions. The field of invention also relates tousing slurry materials to complete extended reach wellbores and extendedreach lateral wellbores. The field of invention also relates to usingslurry materials to complete extended reach wellbores and extended reachlateral wellbores from offshore platforms.

The field of the invention further relates to the use of retrievableinstrumentation packages to perform LWD/MWD logging and directionaldrilling functions while the well is being drilled, which areparticularly useful for the one pass drilling of oil and gas wells, andwhich are also useful for standard well completions, and which can alsobe retrieved by a wireline attached to a Smart Shuttle having retrievalapparatus. The field of the invention further relates to the use ofSmart Shuttles having retrieval apparatus that are capable of deployingand installing into pipes smart completion devices that are used toautomatically complete oil and gas wells after the pipes are disposed inthe wellbore, which are useful for one pass drilling and for standardcased well completions, and these pipes include the following: a drillpipe, a drill string, a casing, a casing string, tubing, a liner, aliner string, a steel pipe, a metallic pipe, or any other pipe used forthe completion of oil and gas wells. The field of the invention furtherrelates to Smart Shuttles that use internal pump means to pump fluidfrom below the Smart Shuttle, to above it, to cause the Smart Shuttle tomove within the pipe to conveniently install smart completion devices.

The field of invention disclosed herein also relates to usingprogressive cavity pumps and electrical submersible motors to make SmartShuttles. The field of invention further relates to closed-loop systemsused to complete oil and gas wells, where the term “to complete a well”means “to finish work on a well and bring it into productive status”. Inthis field of the invention, a closed-loop system to complete an oil andgas well is an automated system under computer control that executes asequence of programmed steps, but those steps depend in part uponinformation obtained from at least one downhole sensor that iscommunicated to the surface to optimize and/or change the steps executedby the computer to complete the well.

The field of invention further relates to a closed-loop system thatexecutes the steps during at least one significant portion of the wellcompletion process and the completed well is comprised of at least aborehole in a geological formation surrounding a pipe located within theborehole, and this pipe may be any one of the following: a metallicpipe; a casing string; a casing string with any retrievable drill bitremoved from the wellbore; a casing string with any drilling apparatusremoved from the wellbore; a casing string with any electricallyoperated drilling apparatus retrieved from the wellbore; a casing stringwith any bicenter bit removed from the wellbore; a steel pipe; anexpandable pipe; an expandable pipe made from any material; anexpandable metallic pipe; an expandable metallic pipe with anyretrievable drill bit removed from the wellbore; an expandable metallicpipe with any drilling apparatus removed from the wellbore; anexpandable metallic pipe with any electrically operated drillingapparatus retrieved from the wellbore; an expandable metallic pipe withany bicenter bit removed from the wellbore; a plastic pipe; a fiberglasspipe; any type of composite pipe; any composite pipe that encapsulatesinsulated wires carrying electricity and/or any tubes containinghydraulic fluid; a composite pipe with any retrievable drill bit removedfrom the wellbore; a composite pipe with any drilling apparatus removedfrom the wellbore; a composite pipe with any electrically operateddrilling apparatus retrieved from the wellbore; a composite pipe withany bicenter bit removed from the wellbore; a drill string; a drillstring possessing a drill bit that remains attached to the end of thedrill string after completing the wellbore; a drill string with anyretrievable drill bit removed from the wellbore; a drill string with anydrilling apparatus removed from the wellbore; a drill string with anyelectrically operated drilling apparatus retrieved from the wellbore; adrill string with any bicenter bit removed from the wellbore; a coiledtubing; a coiled tubing possessing a mud-motor drilling apparatus thatremains attached to the coiled tubing after completing the wellbore; acoiled tubing left in place after any mud-motor drilling apparatus hasbeen removed; a coiled tubing left in place after any electricallyoperated drilling apparatus has been retrieved from the wellbore; aliner made from any material; a liner with any retrievable drill bitremoved from the wellbore; a liner with any liner drilling apparatusremoved from the wellbore; a liner with any electrically operateddrilling apparatus retrieved from the liner; a liner with any bicenterbit removed from the wellbore; any other pipe made of any material withany type of drilling apparatus removed from the pipe; or any other pipemade of any material with any type of drilling apparatus removed fromthe wellbore.

The field of invention further relates to a closed-loop system thatexecutes the steps during at least one significant portion of the wellcompletion process and the completed well is comprised of at least aborehole in a geological formation surrounding a pipe that may beaccessed through other pipes including surface pipes, production lines,subsea production lines, etc.

Following the closed-loop well completion, the field of inventionfurther relates to using well completion apparatus to monitor and/orcontrol the production of hydrocarbons from the within wellbore.

The field of invention also relates to closed-loop systems to completeoil and gas wells that are useful for the one pass drilling andcompletion of oil and gas wells.

The field of the invention further relates to the closed-loop control ofa tractor deployer that may also be used to complete an oil and gaswell.

The invention further relates to the tractor deployer that is used tocomplete a well, perform production and maintenance services on a well,and to perform enhanced recovery services on a well.

And finally, the invention further relates to the tractor deployer thatis connected to surface instrumentation by a substantially neutrallybuoyant umbilical made from composite materials.

2. Description of the Prior Art

At the time of the filing of the application herein, the applicant isunaware of any prior art that is particularly relevant to the inventionother than that cited in the above defined “related” U.S. Patents, the“related” co-pending U.S. Patent Applications, and the “related” U.S.Disclosure Documents that are specified in the first paragraphs of thisapplication.

SUMMARY OF THE INVENTION

In disclosure of related cases, apparatus and methods of operation ofthat apparatus are disclosed that allow for cementation of a drillstring with attached drill bit into place during one single drillingpass into a geological formation. The process of drilling the well andinstalling the casing becomes one single process that saves installationtime and reduces costs during oil and gas well completion procedures.Apparatus and methods of operation of the apparatus are disclosed thatuse the typical mud passages already present in a typical rotary drillbit, including any watercourses in a “regular bit”, or mud jets in a“jet bit”, for the second independent purpose of passing cement into theannulus between the casing and the well while cementing the drill stringin place. This is a crucial step that allows a “Typical DrillingProcess” involving some 14 steps to be compressed into the “New DrillingProcess” that involves only 7 separate steps as described in theDescription of the Preferred Embodiments below. The New Drilling Processis now possible because of “Several Recent Changes in the Industry” alsodescribed in the Description of the Preferred Embodiments below. Inaddition, the New Drilling Process also requires new apparatus toproperly allow the cement to cure under ambient hydrostatic conditions.That new apparatus includes a Latching Subassembly, a Latching FloatCollar Valve Assembly, the Bottom Wiper Plug, and the Top Wiper Plug.Suitable methods of operation are disclosed for the use of the newapparatus. Methods are further disclosed wherein different types ofslurry materials are used for well completion that include at leastcement, gravel, water, a “cement clinker”, and any “blast furnace slagmixture”. Methods are further disclosed using a slurry material tocomplete wells including at least the following: open-hole wellcompletions; cemented well completions having a perforated casing;gravel well completions having perforated casings; extended reachwellbores; extended reach lateral wellbores; and extended reach lateralwellbores completed from offshore drilling platforms.

In yet further disclosure in related cases involving the one passdrilling and completion of wellbores that is also useful for other wellcompletion purposes, Smart Shuttles are used to complete the oil and gaswells. Following drilling operations into a geological formation, asteel pipe is disposed in the wellbore. In the following, any pipe maybe used, but an example of steel pipe is used in the following examplesfor the purposes of simplicity only. The steel pipe may be a standardcasing installed into the wellbore using typical industry practices.Alternatively, the steel pipe may be a drill string attached to a rotarydrill bit that is to remain in the wellbore following completion duringso-called “one pass drilling operations”. Further, the steel pipe may bea drill pipe from which has been removed a retrievable or retractabledrill bit. Or, the steel pipe may be a coiled tubing having a mud motordrilling apparatus at its end. Using typical procedures in the industry,the well is “completed” by placing into the steel pipe various standardcompletion devices, some of which are conveyed into place with thedrilling rig. Here, instead, Smart Shuttles are used to convey into thesteel pipe various smart completion devices used to complete the oil andgas well. The Smart Shuttles are then used to install various smartcompletion devices. And the Smart Shuttles may be used to retrieve fromthe wellbore various smart completion devices. Smart Shuttles may beattached to a wireline, coiled tubing, or to a wireline installed withincoiled tubing, and such applications are called “tethered SmartShuttles”. Smart Shuttles may be robotically independent of thewireline, etc., provided that large amounts of power are not requiredfor the completion device, and such devices are called “untetheredshuttles”. The smart completion devices are used in some cases tomachine portions of the steel pipe. Completion substances, such ascement, gravel, etc. are introduced into the steel pipe using smartwiper plugs and Smart Shuttles as required. Smart Shuttles may berobotically and automatically controlled from the surface of the earthunder computer control so that the completion of a particular oil andgas well proceeds automatically through a progression of steps. Awireline attached to a Smart Shuttle may be used to energize devicesfrom the surface that consume large amounts of power. Pressure controlat the surface is maintained by use of a suitable lubricator device thathas been modified to have a Smart Shuttle chamber suitably accessiblefrom the floor of the drilling rig. A particular Smart Shuttle ofinterest is a wireline conveyed Smart Shuttle that possesses anelectrically operated internal pump that pumps fluid from below theshuttle to above the shuttle that causes the Smart Shuttle to pumpitself down into the well. Suitable valves that open allow for theretrieval of the Smart Shuttle by pulling up on the wireline. Similarcomments apply to coiled tubing conveyed Smart Shuttles. Using SmartShuttles to complete oil and gas wells reduces the amount of time thedrilling rig is used for standard completion purposes. The SmartShuttles therefore allow the use of the drilling rig for its basicpurpose—the drilling of oil and gas wells.

In disclosure herein, a closed-loop system is used to complete oil andgas wells. The term “to complete a well” means “to finish work on a welland bring it into productive status”. A closed-loop system to completean oil and gas well is an automated system under computer control thatexecutes a sequence of programmed steps, but those steps depend in partupon information obtained from at least one downhole sensor that iscommunicated to the surface to optimize and/or change the steps executedby the computer to complete the well. The closed-loop system executesthe steps during at least one significant portion of the well completionprocess. A type of Smart Shuttle comprised of a progressive cavity pumpand an electrical submersible motor is particularly useful for suchclosed-loop systems. The completed well is comprised of at least aborehole in a geological formation surrounding a pipe located within theborehole. The pipe may be a metallic pipe; a casing string; a casingstring with any retrievable drill bit removed from the wellbore; a steelpipe; a drill string; a drill string possessing a drill bit that remainsattached to the end of the drill string after completing the wellbore; adrill string with any retrievable drill bit removed from the wellbore; acoiled tubing; a coiled tubing possessing a mud-motor drilling apparatusthat remains attached to the coiled tubing after completing thewellbore; or a liner. Following the closed-loop well completion,apparatus monitoring the production of hydrocarbons from the withinwellbore may be used to control the production of hydrocarbons from thewellbore. The closed-loop completion of oil and gas wells providesapparatus and methods of operation to substantially reduce the number ofsteps, the complexity, and the cost to complete oil and gas wells.

Accordingly, the closed-loop completion of oil and gas wells is asubstantial improvement over present technology in the oil and gasindustries.

The closed-loop control of a tractor deployer may also be used tocomplete an oil and gas well. Tractor deployer is used to complete awell, perform production and maintenance services on a well, and toperform enhanced recovery services on a well. The well servicing tractordeployer may be connected to surface instrumentation by a neutrallybuoyant umbilical. Some of these umbilicals are made from compositematerials.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a section view of a rotary drill string having a rotarydrill bit in the process of being cemented in place during one drillingpass into formation by using a Latching Float Collar Valve Assembly thathas been pumped into place above the rotary drill bit that is apreferred embodiment of the invention.

FIG. 2 shows a section view of a rotary drill string having a rotarydrill bit in the process of being cemented into place during onedrilling pass into formation by using a Permanently Installed FloatCollar Valve Assembly that is permanently installed above the rotarydrill bit that is a preferred embodiment of the invention.

FIG. 3 shows a section view of a tubing conveyed mud motor drillingapparatus in the process of being cemented into place during onedrilling pass into formation by using a Latching Float Collar ValveAssembly that has been pumped into place above the mud motor assemblythat is a preferred embodiment of the invention.

FIG. 4 shows a section view of a tubing conveyed mud motor drillingapparatus that in addition has several wiper plugs in the process ofsequentially completing the well with gravel and then with cement duringthe one pass drilling and completion of the wellbore.

FIG. 5 shows a section view of an apparatus for the one pass drillingand completion of extended reach lateral wellbores with drill bitattached to a rotary drill string to produce hydrocarbons from offshoreplatforms.

FIG. 6 shows a section view of a embodiment of the invention that isparticularly configured so that Measurement-While-Drilling (MWD) andLogging-While-Drilling (LWD) can be done during rotary drillingoperations with a Retrievable Instrumentation Package installed in placewithin a Smart Drilling and Completion Sub near the drill bit which isuseful for the one pass drilling and completion of wellbores and whichis also useful for standard well drilling procedures.

FIG. 7 shows a section view of the Retrievable Instrumentation Packageand the Smart Drilling and Completion Sub that also has directionaldrilling control apparatus and instrumentation which is useful for theone pass drilling and completion of wellbores and which is also usefulfor standard well drilling operations.

FIG. 8 shows a section view of the wellhead, the Wiper Plug Pump-DownStack, the Smart Shuttle Chamber, the Wireline Lubricator System, theSmart Shuttle and the Retrieval Sub suspended by the wireline which isuseful for the one pass drilling and completion of wellbores, and whichis also useful for the completion of wells using cased well completionprocedures.

FIG. 9 shows a section view in detail of the Smart Shuttle and theRetrieval Sub while located in the Smart Shuttle Chamber.

FIG. 10 shows a section view of the Smart Shuttle and the Retrieval Subin a position where the elastomer sealing elements of the Smart Shuttlehave sealed against the interior of the pipe, and the internal pump ofthe Smart Shuttle is ready to pump fluid volumes ΔV1 from below theSmart Shuttle to above it so that the Smart Shuttle translates downhole.

FIG. 11 is a generalized block diagram of one embodiment of a SmartShuttle having a first electrically operated positive displacement pumpand a second electrically operated pump.

FIG. 12 shows a block diagram of a pump transmission device thatprevents pump stalling, and other pump problems, by matching the loadseen by the pump to the power available from the motor within the SmartShuttle.

FIG. 13 shows a block diagram of preferred embodiment of a Smart Shuttlehaving a hybrid pump design that also provides for a turbine assemblythat causes a traction wheel to engage the casing to cause translationof the Smart Shuttle.

FIG. 14 shows a block diagram of the computer control of the wirelinedrum and the Smart Shuttle in a preferred embodiment of the inventionthat allows the system to be operated as an Automated Smart ShuttleSystem, or “closed-loop completion system”, that is useful for theclosed-loop completion of one pass drilling operations, and that is alsouseful for completion operations within a standard casing string.

FIG. 15 shows a section view of a rubber-type material wiper plug thatcan be attached to the Retrieval Sub and placed into the Wiper PlugPump-Down Stack and subsequently used for the well completion process.

FIG. 16 shows a section view of the Casing Saw that can be attached tothe Retrieval Sub and conveyed downhole with the Smart Shuttle.

FIG. 17 shows a section view of the wellhead, the Wiper Plug Pump-DownStack, the Smart Shuttle Chamber, the Coiled Tubing Lubricator System,and the pump-down single zone packer apparatus suspended by the coiledtubing in the well before commencing the final single-zone completion ofthe well which in this case pertains to the one pass drilling andcompletion of wellbores, but that is also useful for standard cased wellcompletions.

FIG. 17A shows an expanded view of the pump-down single zone packerapparatus that is shown in FIG. 17.

FIG. 18 shows a “pipe means” deployed in the wellbore that may be a pipemade of any material, a metallic pipe, a steel pipe, a composite pipe, adrill pipe, a drill string, a casing, a casing string, a liner, a linerstring, tubing, or a tubing string, or any means to convey oil and gasto the surface for production that may be completed using a SmartShuttle, Retrieval Sub, and Smart Completion Devices. The “pipe means”is explicitly shown here so that it is crystal clear that variouspreferred embodiments cited above for use during the one pass drillingand completion of oil and gas wells can in addition also be used instandard well drilling and casing operations.

FIG. 18A shows a modified and expanded form of FIG. 18 wherein the lastportion of the “pipe means” has “pipe mounted latching means” that maybe used for a number of purposes including attaching a retrievable drillbit and/or as a positive “stop” for a pump-down one-way valve meansfollowing the retrieval of the retrievable drill bit during one passdrilling and completion operations.

FIG. 19 shows a particular preferred embodiment of a Smart Shuttlehaving a Progressive Cavity Pump (“PCP”) and a gear box that is in turndriven by an Electrical Submersible Motor (“ESM”) that is used in drillpipes during one pass drilling and completion operations and that isalso used in standard casing strings and within other “pipe means” thatis particularly useful for the closed-loop completion of oil and gaswells.

FIG. 20 shows one embodiment of a Smart Shuttle having a PCP and ESMthat also has an adjustable sealing means for operation in pipes havingvariable inside diameters and for other purposes that is particularlyuseful for the closed-loop completion of oil and gas wells.

FIG. 21 shows a standard casing string, or other pipe, in the process ofbeing completed with a Smart Shuttle, a Retrieval Sub, and a Casing Saw,along with other completion devices that had previously been installedwithin the casing string during the closed-loop completion of the well.

FIG. 22 shows a section view of the pump-down single zone packerapparatus installed in a standard casing string, or other pipe,following completion operations with the Smart Shuttle and othercompletion devices shown in FIG. 21, and such pump-down single zonepacker apparatus is particularly useful for the closed-loop completionof oil and gas wells.

FIG. 23 shows a Smart Shuttle and Retrieval Sub in a standard casing, orother pipe, being conveyed downhole which are attached to a coiledtubing having a wireline within the tubing that is particularly usefulfor the closed-loop completion of oil and gas wells.

FIG. 24 shows a Universal Smart Completion Device (USCD) that isconveyed downhole by attachment to a Smart Shuttle and its Retrieval Subthat is particularly useful as an element in a closed-loop system tocomplete oil and gas wells.

FIG. 25 shows two Universal Smart Completion Devices installed duringclosed-loop completion operations to make a TAML Level 5 WellCompletion.

FIG. 26 shows in diagrammatic form a closed-loop subsea completionsystem.

FIG. 27 shows the tractor deployer operated by a wireline.

FIG. 28 shows various devices that may be attached to the Retrieval Subof the Smart Shuttle and the tractor conveyor.

FIG. 29 that shows a diagrammatic representation of functions that maybe performed with the Smart Shuttle and the tractor conveyance system.

FIG. 30 shows the tractor deployer operated from an umbilical.

FIG. 31 shows a cross section of an embodiment of the umbilical shown inFIG. 30.

FIG. 32 shows another neutrally buoyant composite umbilical in 12 lb pergallon mud.

FIG. 33 shows an electrical block diagram representing two conductorsfrom a three phase delta system providing up to 160 horsepower ofelectrical power at a distance of 20 miles.

FIG. 34 shows a block diagram showing feedback control of voltagedelivered downhole to an electrical motor.

FIG. 35 shows an umbilical that is substantially neutrally buoyant in 12lb per gallon mud which also provides a conduit for fluids.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following disclosure related to FIGS. 1-5 is substantially repeatedherein from co-pending Ser. No. 09/295,808. This repeated disclosurerelated to FIGS. 1-5 is useful information so that the preferredembodiments of the invention herein may be economically described interms of previous definitions related to those FIGS. 1-5.

In FIGS. 1-5, apparatus and methods of operation of that apparatus aredisclosed herein in the preferred embodiments of the invention thatallow for cementation of a drill string with attached drill bit intoplace during one single drilling pass into a geological formation. Themethod of drilling the well and installing the casing becomes one singleprocess that saves installation time and reduces costs during oil andgas well completion procedures as documented in the followingdescription of the preferred embodiments of the invention. Apparatus andmethods of operation of the apparatus are disclosed herein that use thetypical mud passages already present in a typical rotary drill bit,including any watercourses in a “regular bit”, or mud jets in a “jetbit”, for the second independent purpose of passing cement into theannulus between the casing and the well while cementing the drill stringin place. Slurry materials may be used for completion purposes inextended lateral wellbores. Therefore, the following text issubstantially quoted from co-pending Ser. No. 09/295,808 related toFIGS. 1-5.

FIG. 1 shows a section view of a drill string in the process of beingcemented in place during one drilling pass into formation. A borehole 2is drilled though the earth including geological formation 4. Theborehole is drilled with a milled tooth rotary drill bit 6 having milledsteel roller cones 8, 10, and 12 (not shown for simplicity). A standardwater passage 14 is shown through the rotary cone drill bit. This rotarybit could equally be a tungsten carbide insert roller cone bit havingjets for waterpassages, the principle of operation and the relatedapparatus being the same for either case for the preferred embodimentherein.

The threads 16 on rotary drill bit 6 are screwed into the LatchingSubassembly 18. The Latching Subassembly is also called the Latching Subfor simplicity herein. The Latching Sub is a relatively thick-walledsteel pipe having some functions similar to a standard drill collar.

The Latching Float Collar Valve Assembly 20 is pumped downhole withdrilling mud after the depth of the well is reached. The Latching FloatCollar Valve Assembly is pumped downhole with mud pressure pushingagainst the Upper Seal 22 of the Latching Float Collar Valve Assembly.The Latching Float Collar Valve Assembly latches into place into LatchRecession 24. The Latch 26 of the Latching Float Collar Valve Assemblyis shown latched into place with Latching Spring 28 pushing againstLatching Mandrel 30. When the Latch 26 is properly seated into placewithin the Latch Recession 24, the clearances and materials of the Latchand mating Latch Recession are to be chosen such that very little cementwill leak through the region of the Latch Recession 24 of the LatchingSubassembly 18 under any back-pressure (upward pressure) in the well.Many means can be utilized to accomplish this task, includingfabricating the Latch 26 from suitable rubber compounds, suitablydesigning the upper portion of the Latching Float Collar Valve Assembly20 immediately below the Upper Seal 22, the use of various O-ringswithin or near Latch Recession 24, etc.

The Float 32 of the Latching Float Collar Valve Assembly seats againstthe Float Seating Surface 34 under the force from Float Collar Spring 36that makes a one-way cement valve. However, the pressure applied to themud or cement from the surface may force open the Float to allow mud orcement to be forced into the annulus generally designated as 38 in FIG.1. This one-way cement valve is a particular example of “a one-waycement valve means installed near the drill bit” which is a term definedherein. The one-way cement valve means may be installed at any distancefrom the drill bit but is preferentially installed “near” the drill bit.

FIG. 1 corresponds to the situation where cement is in the process ofbeing forced from the surface through the Latching Float Collar ValveAssembly. In fact, the top level of cement in the well is designated aselement 40. Below 40, cement fills the annulus of the borehole. Above40, mud fills the annulus of the borehole. For example, cement ispresent at position 42 and drilling mud is present at position 44 inFIG. 1.

Relatively thin-wall casing, or drill pipe, designated as element 46 inFIG. 1, is attached to the Latching Sub. The bottom male threads of thedrill pipe 48 are screwed into the female threads 50 of the LatchingSub.

The drilling mud was wiped off the walls of the drill pipe in the wellwith Bottom Wiper Plug 52. The Bottom Wiper Plug is fabricated fromrubber in the shape shown. Portions 54 and 56 of the Upper Seal of theBottom Wiper Plug are shown in a ruptured condition in FIG. 1.Initially, they sealed the upper portion of the Bottom Wiper Plug. Underpressure from cement, the Bottom Wiper Plug is pumped down into the welluntil the Lower Lobe of the Bottom Wiper Plug 58 latches into place intoLatching Sub Recession 60 in the Latching Sub. After the Bottom WiperPlug latches into place, the pressure of the cement ruptures The UpperSeal of the Bottom Wiper Plug. A Bottom Wiper Plug Lobe 62 is shown inFIG. 1. Such lobes provide an efficient means to wipe the mud off thewalls of the drill pipe while the Bottom Wiper Plug is pumped downholewith cement.

Top Wiper Plug 64 is being pumped downhole by water 66 under pressure inthe drill pipe. As the Top Wiper Plug 64 is pumped down under waterpressure, the cement remaining in region 68 is forced downward throughthe Bottom Wiper Plug, through the Latching Float Collar Valve Assembly,through the waterpassages of the drill bit and into the annulus in thewell. A Top Wiper Plug Lobe 70 is shown in FIG. 1. Such lobes provide anefficient means to wipe the cement off the walls of the drill pipe whilethe Top Wiper Plug is pumped downhole with water.

After the Bottom Surface 72 of the Top Wiper Plug is forced into the TopSurface 74 of the Bottom Wiper Plug, almost the entire “cement charge”has been forced into the annulus between the drill pipe and the hole. Aspressure is reduced on the water, the Float of the Latching FloatLatching Float Collar Valve Assembly seals against the Float SeatingSurface 34. As the water pressure is reduced on the inside of the drillpipe, then the cement in the annulus between the drill pipe and the holecan cure under ambient hydrostatic conditions. This procedure hereinprovides an example of the proper operation of a “one-way cement valvemeans”.

Therefore, the preferred embodiment in FIG. 1 provides apparatus thatuses the steel drill string attached to a drilling bit during drillingoperations used to drill oil and gas wells for a second purpose as thecasing that is cemented in place during typical oil and gas wellcompletions.

The preferred embodiment in FIG. 1 provides apparatus and methods ofoperation of the apparatus that results in the efficient installation ofa cemented steel cased well during one single pass down into the earthof the steel drill string thereby making a steel cased borehole or casedwell.

The steps described herein in relation to the preferred embodiment inFIG. 1 provide a method of operation that uses the typical mud passagesalready present in a typical rotary drill bit, including anywatercourses in a “regular bit”, or mud jets in a “jet bit”, that allowmud to circulate during typical drilling operations for the secondindependent, and the distinctly separate, purpose of passing cement intothe annulus between the casing and the well while cementing the drillstring into place during one single pass into the earth.

The preferred embodiment of the invention further provides apparatus andmethods of operation that results in the pumping of cement down thedrill string, through the mud passages in the drill bit, and into theannulus between the formation and the drill string for the purpose ofcementing the drill string and the drill bit into place during onesingle drilling pass into the formation.

The apparatus described in the preferred embodiment in FIG. 1 alsoprovide a one-way cement valve and related devices installed near thedrill bit of the drill string that allows the cement to set upefficiently while the drill string and drill bit are cemented into placeduring one single drilling pass into the formation.

Methods of operation of apparatus disclosed in FIG. 1 have beendisclosed that use the typical mud passages already present in a typicalrotary drill bit, including any watercourses in a “regular bit”, or mudjets in a “jet bit”, for the second independent purpose of passingcement into the annulus between the casing and the well while cementingthe drill string in place. This is a crucial step that allows a “TypicalDrilling Process” involving some 14 steps to be compressed into the “NewDrilling Process” that involves only 7 separate steps as described indetail below. The New Drilling Process is now possible because of“Several Recent Changes in the Industry” also described in detail below.

Typical procedures used in the oil and gas industries to drill andcomplete wells are well documented. For example, such procedures aredocumented in the entire “Rotary Drilling Series” published by thePetroleum Extension Service of The University of Texas at Austin,Austin, Tex. that is incorporated herein by reference in its entiretycomprised of the following: Unit I—“The Rig and Its Maintenance” (12Lessons); Unit II—“Normal Drilling Operations” (5 Lessons); UnitIII—Nonroutine Rig Operations (4 Lessons); Unit IV—Man Management andRig Management (1 Lesson); and Unit V—Offshore Technology (9 Lessons).All of the individual Glossaries of all of the above Lessons in theirentirety are also explicitly incorporated herein, and all definitions inthose Glossaries shall be considered to be explicitly referenced and/ordefined herein.

Additional procedures used in the oil and gas industries to drill andcomplete wells are well documented in the series entitled “Lessons inWell Servicing and Workover” published by the Petroleum ExtensionService of The University of Texas at Austin, Austin, Tex. that isincorporated herein by reference in its entirety comprised of all 12Lessons. All of the individual Glossaries of all of the above Lessons intheir entirety are also explicitly incorporated herein, and any and alldefinitions in those Glossaries shall be considered to be explicitlyreferenced and/or defined herein.

With reference to typical practices in the oil and gas industries, atypical drilling process may therefore be described in the following.

Typical Drilling Process

From an historical perspective, completing oil and gas wells usingrotary drilling techniques have in recent times comprised the followingtypical steps:

Step 1. With a pile driver or rotary rig, install any necessaryconductor pipe on the surface for attachment of the blowout preventerand for mechanical support at the wellhead.

Step 2. Install and cement into place any surface casing necessary toprevent washouts and cave-ins near the surface, and to prevent thecontamination of freshwater sands as directed by state and federalregulations.

Step 3. Choose the dimensions of the drill bit to result in the desiredsized production well. Begin rotary drilling of the production well witha first drill bit. Simultaneously circulate drilling mud into the wellwhile drilling. Drilling mud is circulated downhole to carry rock chipsto the surface, to prevent blowouts, to prevent excessive mud loss intoformation, to cool the bit, and to clean the bit. After the first bitwears out, pull the drill string out, change bits, lower the drillstring into the well and continue drilling. It should be noted here thateach “trip” of the drill bit typically requires many hours of rig timeto accomplish the disassembly and reassembly of the drill string, pipesegment by pipe segment. Here, each pipe segment may consist of severalpipe joints.

Step 4. Drill the production well using a succession of rotary drillbits attached to the drill string until the hole is drilled to its finaldepth.

Step 5. After the final depth is reached, pull out the drill string andits attached drill bit.

Step 6. Perform open-hole logging of the geological formations todetermine the quantitative amounts of oil and gas present. Thistypically involves making physical measurements that are used todetermine the porosity of the rock, the electrical resistivity of thewater present, the electrical resistivity of the rock, the total amountsof oil and gas present, the relative amounts of oil and gas present, andthe use of Archie's Equations (or their equivalent representation, ortheir approximation by other algebraic expressions, or theirsubstitution for similar geophysical analysis). Here, such open-holephysical measurements include electrical measurements, inductivemeasurements, acoustic measurements, natural gamma ray measurements,neutron measurements, and other types of nuclear measurements, etc. Suchmeasurements may also be used to determine the permeability of the rock.If no oil and gas is present from the analysis of such open-hole logs,an option can be chosen to cement the well shut. If commercial amountsof oil and gas are present, continue the following steps.

Step 7. Typically reassemble the drill bit and the drill string in thewell to clean the well after open-hole logging.

Step 8. Pull out the drill string and its attached drill bit.

Step 9. Attach the casing shoe into the bottom male pipe threads of thefirst length of casing to be installed into the well. This casing shoemay or may not have a one-way valve (“casing shoe valve”) installed inits interior to prevent fluids from back-flowing from the well into thecasing string.

Step 10. Typically install the float collar onto the top female threadsof the first length of casing to be installed into the well which has aone-way valve (“float collar valve”) that allows the mud and cement topass only one way down into the hole thereby preventing any fluids fromback-flowing from the well into the casing string. Therefore, a typicalinstallation has a casing shoe attached to the bottom and the floatcollar valve attached to the top portion of the first length of casingto be lowered into the well. The float collar and the casing shoe areoften installed into one assembly for convenience that entirely replacethis first length of casing. Please refer to the book entitled “Casingand Cementing”, Unit II, Lesson 4, Second Edition, of the RotaryDrilling Series, Petroleum Extension Service, The University of Texas atAustin, Austin, Tex., 1982 (hereinafter defined as “Ref.1”, an entirecopy of which is incorporated herein by reference. In particular, pleaserefer to pages 28-35 of that book (Ref. 1). All of the individualdefinitions of words and phrases in the Glossary of Ref. 1 are alsoexplicitly and separately incorporated herein in their entirety byreference.

Step 11. Assemble and lower the production casing into the well whileback filling each section of casing with mud as it enters the well toovercome the buoyancy effects of the air filled casing (caused by thepresence of the float collar valve), to help avoid sticking problemswith the casing, and to prevent the possible collapse of the casing dueto accumulated build-up of hydrostatic pressure.

Step 12. To “cure the cement under ambient hydrostatic conditions”,typically execute a two-plug cementing procedure involving a firstBottom Wiper Plug before and a second Top Wiper Plug behind the cementthat also minimizes cement contamination problems comprised of thefollowing individual steps:

-   -   A. Introduce the Bottom Wiper Plug into the interior of the        steel casing assembled in the well and pump down with cement        that cleans the mud off the walls and separates the mud and        cement (Ref. 1, pages 28-35).    -   B. Introduce the Top Wiper Plug into the interior of the steel        casing assembled into the well and pump down with water under        pump pressure thereby forcing the cement through the float        collar valve and any other one-way valves present (Ref. 1, pages        28-35).

C. After the Bottom Wiper Plug and the Top Wiper Plug have seated in thefloat collar, release the pump pressure on the water column in thecasing that results in the closing of the float collar valve which inturn prevents cement from backing up into the interior of the casing.The resulting interior pressure release on the inside of the casing uponclosure of the float collar valve prevents distortions of the casingthat might prevent a good cement seal (Ref. 1, page 30). In suchcircumstances, “the cement is cured under ambient hydrostaticconditions”.

Step 13. Allow the cement to cure.

Step 14. Follow normal “final completion operations” that includeinstalling the tubing with packers and perforating the casing near theproducing zones. For a description of such normal final completionoperations, please refer to the book entitled “Well Completion Methods”,Well Servicing and Workover, Lesson 4, from the series entitled “Lessonsin Well Servicing and Workover”, Petroleum Extension Service, TheUniversity of Texas at Austin, Austin, Tex., 1971 (hereinafter definedas “Ref. 2”), an entire copy of which is incorporated herein byreference. All of the individual definitions of words and phrases in theGlossary of Ref. 2 are also explicitly and separately incorporatedherein in their entirety by reference. Other methods of completing thewell are described therein that shall, for the purposes of thisapplication herein, also be called “final completion operations”.

Several Recent Changes in the Industry

Several recent concurrent changes in the industry have made it possibleto reduce the number of steps defined above. These changes include thefollowing:

a. Until recently, drill bits typically wore out during drillingoperations before the desired depth was reached by the production well.However, certain drill bits have recently been able to drill a holewithout having to be changed. For example, please refer to the bookentitled “The Bit”, Unit I, Lesson 2, Third Edition, of the RotaryDrilling Series, The University of Texas at Austin, Austin, Tex., 1981(hereinafter defined as “Ref. 311), an entire copy of which isincorporated herein by reference. All of the individual definitions ofwords and phrases in the Glossary of Ref. 3 are also explicitly andseparately incorporated herein in their entirety by reference. On page 1of Ref. 3 it states: “For example, often only one bit is needed to makea hole in which the casing will be set.” On page 12 of Ref. 3 it statesin relation to tungsten carbide insert roller cone bits: “Bit runs aslong as 300 hours have been achieved; in some instances, only one or twobits have been needed to drill a well to total depth.” This isparticularly so since the advent of the sealed bearing tri-cone bitdesigns appeared in 1959 (Ref. 3, page 7) having tungsten carbideinserts (Ref. 3, page 12). Therefore, it is now practical to talk aboutdrill bits lasting long enough for drilling a well during one pass intothe formation, or “one pass drilling”.

b. Until recently, it has been impossible or impractical to obtainsufficient geophysical information to determine the presence or absenceof oil and gas from inside steel pipes in wells. Heretofore, eitherstandard open-hole logging tools or Measurement-While-Drilling (“MWD”)tools were used in the open hole to obtain such information. Therefore,the industry has historically used various open-hole tools to measureformation characteristics. However, it has recently become possible tomeasure the various geophysical quantities listed in Step 6 above frominside steel pipes such as drill strings and casing strings. Forexample, please refer to the book entitled “Cased Hole LogInterpretation Principles/Applications”, Schlumberger EducationalServices, Houston, Tex., 1989, an entire copy of which is incorporatedherein by reference. Please also refer to the article entitled“Electrical Logging: State-of-the-Art”, by Robert E. Maute, The LogAnalyst, May-June 1992, pages 206-227, an entire copy of which isincorporated herein by reference.

Because drill bits typically wore out during drilling operations untilrecently, different types of metal pipes have historically evolved whichare attached to drilling bits, which, when assembled, are called “drillstrings”. Those drill strings are different than typical “casingstrings” run into the well. Because it was historically absolutelynecessary to do open-hole logging to determine the presence or absenceof oil and gas, the fact that different types of pipes were used in“drill strings” and “casing strings” was of little consequence to theeconomics of completing wells. However, it is possible to choose the“drill string” to be acceptable for a second use, namely as the “casingstring” that is to be installed after drilling has been completed.

New Drilling Process

Therefore, the preferred embodiments of the invention herein reduces andsimplifies the above 14 steps as follows:

Repeat Steps 1-2 above.

Steps 3-5 (Revised). Choose the drill bit so that the entire productionwell can be drilled to its final depth using only one single drill bit.Choose the dimensions of the drill bit for desired size of theproduction well. If the cement is to be cured under ambient hydrostaticconditions, attach the drill bit to the bottom female threads of theLatching Subassembly (“Latching Sub”). Choose the material of the drillstring from pipe material that can also be used as the casing string.Here, any pipe made of any material may be used including metallic pipe,composite pipe, fiberglass pipe, and hybrid pipe made of a mixture ofdifferent materials, etc. As an example, a composite pipe may bemanufactured from carbon fiber-epoxy resin materials. Attach the firstsection of drill pipe to the top female threads of the Latching Sub.Then rotary drill the production well to its final depth during “onepass drilling” into the well. While drilling, simultaneously circulatedrilling mud to carry the rock chips to the surface, to preventblowouts, to prevent excessive mud loss into formation, to cool the bit,and to clean the bit.

Step 6 (Revised). After the final depth of the production well isreached, perform logging of the geological formations to determine theamount of oil and gas present from inside the drill pipe of the drillstring. This typically involves measurements from inside the drillstring of the necessary geophysical quantities as summarized in Item“b.” of “Several Recent Changes in the Industry”. If such logs obtainedfrom inside the drill string show that no oil or gas is present, thenthe drill string can be pulled out of the well and the well filled inwith cement. If commercial amounts of oil and gas are present, continuethe following steps.

Steps 7-11 (Revised). If the cement is to be cured under ambienthydrostatic conditions, pump down a Latching Float Collar Valve Assemblywith mud until it latches into place in the notches provided in theLatching Sub located above the drill bit.

Steps 12-13 (Revised). To “cure the cement under ambient hydrostaticconditions”, typically execute a two-plug cementing procedure involvinga first Bottom Wiper Plug before and a second Top Wiper Plug behind thecement that also minimizes cement contamination comprised of thefollowing individual steps:

-   -   A. Introduce the Bottom Wiper Plug into the interior of the        drill string assembled in the well and pump down with cement        that cleans the mud off the walls and separates the mud and        cement.    -   B. Introduce the Top Wiper Plug into the interior of the drill        string assembled into the well and pump down with water thereby        forcing the cement through any Float Collar Valve Assembly        present and through the watercourses in “a regular bit” or        through the mud nozzles of a “jet bit” or through any other mud        passages in the drill bit into the annulus between the drill        string and the formation.    -   C. After the Bottom Wiper Plug, and Top Wiper Plug have seated        in the Latching Float Collar Valve Assembly, release the        pressure on the interior of the drill string that results in the        closing of the float collar which in turn prevents cement from        backing up in the drill string. The resulting pressure release        upon closure of the float collar prevents distortions of the        drill string that might prevent a good cement seal as described        earlier. I.e., “the cement is cured under ambient hydrostatic        conditions”.

Repeat Step 14 above.

Therefore, the “New Drilling Process” has only 7 distinct steps insteadof the 14 steps in the “Typical Drilling Process”. The “New DrillingProcess” consequently has fewer steps, is easier to implement, and willbe less expensive. The “New Drilling Process” takes less time to drill awell. This faster process has considerable commercial significance.

The preferred embodiment of the invention disclosed in FIG. 1 requires aLatching Subassembly and a Latching Float Collar Valve Assembly. Anadvantage of this approach is that the Float 32 of the Latching FloatCollar Valve Assembly and the Float Seating Surface 34 in FIG. 1 areinstalled at the end of the drilling process and are not subject to anywear by mud passing down during normal drilling operations.

Another preferred embodiment of the invention provides a float and floatcollar valve assembly permanently installed within the LatchingSubassembly at the beginning of the drilling operations. However, such apreferred embodiment has the disadvantage that drilling mud passing bythe float and the float collar valve assembly during normal drillingoperations could subject the mutually sealing surfaces to potentialwear. Nevertheless, a float collar valve assembly can be permanentlyinstalled above the drill bit before the drill bit enters the well.

Permanently Installed One-Way Valve

FIG. 2 shows another preferred embodiment of the invention that has sucha float collar valve assembly permanently installed above the drill bitbefore the drill bit enters the well. FIG. 2 shows many elements commonto FIG. 1. The Permanently Installed Float Collar Valve Assembly 76,hereinafter abbreviated as the “PIFCVA”, is installed into the drillstring on the surface of the earth before the drill bit enters the well.On the surface, the threads 16 on the rotary drill bit 6 are screwedinto the lower female threads 78 of the PIFCVA. The bottom male threadsof the drill pipe 48 are screwed into the upper female threads 80 of thePIFCVA. The PIFCVA Latching Sub Recession 82 is similar in nature andfunction to element 60 in FIG. 1. The fluids flowing thorough thestandard water passage 14 of the drill bit flow through PIFCVA GuideChannel 84. The PIFCVA Float 86 has a Hardened Hemispherical Surface 88that seats against the hardened PIFCVA Float Seating Surface 90 underthe force PIFCVA Spring 92. Surfaces 88 and 90 may be fabricated fromvery hard materials such as tungsten carbide. Alternatively, anyhardening process in the metallurgical arts may be used to harden thesurfaces of standard steel parts to make suitable hardened surfaces 88and 90. The lower surfaces of the PIFCVA Spring 92 seat against theupper portion of the PIFCVA Threaded Spacer 94 that has PIFCVA ThreadedSpacer Passage 96. The PIFCVA Threaded Spacer 94 has exterior threadsthat thread into internal threads 100 of the PIFCVA (that is assembledinto place within the PIFCVA prior to attachment of the drill bit to thePIFCVA). Surface 102 facing the lower portion of the PIFCVA GuideChannel 84 may also be made from hardened materials, or otherwisesurface hardened, so as to prevent wear from the mud flowing throughthis portion of the channel during drilling.

Once the PIFCVA is installed into the drill string, then the drill bitis lowered into the well and drilling commenced. Mud pressure from thesurface opens PIFCVA Float 86. The steps for using the preferredembodiment in FIG. 2 are slightly different than using that shown inFIG. 1. Basically, the “Steps 7-11 (Revised)” of the “New DrillingProcess” are eliminated because it is not necessary to pump down anytype of Latching Float Collar Valve Assembly of the type described inFIG. 1. In “Steps 3-5 (Revised)” of the “New Drilling Process”, it isevident that the PIFCVA is installed into the drill string instead ofthe Latching Subassembly appropriate for FIG. 1. In Steps 12-13(Revised) of the “New Drilling Process”, it is also evident that theLower Lobe of the Bottom Wiper Plug 58 latches into place into thePIFCVA Latching Sub Recession 82.

The PIFCVA installed into the drill string is another example of aone-way cement valve means installed near the drill bit to be usedduring one pass drilling of the well. Here, the term “near” shall meanwithin 500 feet of the drill bit. Consequently, FIG. 2 describes arotary drilling apparatus to drill a borehole into the earth comprisinga drill string attached to a rotary drill bit and one-way cement valvemeans installed near the drill bit to cement the drill string and rotarydrill bit into the earth to make a steel cased well. Here, in thispreferred embodiment, the method of drilling the borehole is implementedwith a rotary drill bit having mud passages to pass mud into theborehole from within a steel drill string that includes at least onestep that passes cement through such mud passages to cement the drillstring into place to make a steel cased well.

The drill bits described in FIG. 1 and FIG. 2 are milled steel toothedroller cone bits. However, any rotary bit can be used with theinvention. A tungsten carbide insert roller cone bit can be used. Anytype of diamond bit or drag bit can be used. The invention may be usedwith any drill bit described in Ref. 3 above that possesses mudpassages, waterpassages, or passages for gas. Any type of rotary drillbit can be used possessing such passageways. Similarly, any type of bitwhatsoever that utilizes any fluid or gas that passes throughpassageways in the bit can be used whether or not the bit rotates.

As another example of “ . . . any type of bit whatsoever . . . ”described in the previous sentence, a new type of drill bit invented bythe inventor of this application can be used for the purposes hereinthat is disclosed in U.S. Pat. No. 5,615,747, that is entitled“Monolithic Self Sharpening Rotary Drill Bit Having Tungsten CarbideRods Cast in Steel Alloys”, that issued on Apr. 1, 1997 (hereinafterVail{747}), an entire copy of which is incorporated herein by reference.That new type of drill bit is further described in a ContinuingApplication of Vail{747} that is now U.S. Pat. No. 5,836,409, that isalso entitled “Monolithic Self Sharpening Rotary Drill Bit HavingTungsten Carbide Rods Cast in Steel Alloys”, that issued on the date ofNov. 17, 1998 (hereinafter Vail{409}), an entire copy of which isincorporated herein by reference. That new type of drill bit is furtherdescribed in a Continuation-in-Part Application of Vail{409} that isSer. No. 09/192,248, that has the filing date of Nov. 16, 1998, that isentitled “Rotary Drill Bit Compensating for Changes in Hardness ofGeological Formations”, an entire copy of which is incorporated hereinby reference. As yet another example of “ . . . any type of bitwhatsoever . . . ” described in the last sentence of the previousparagraph, FIG. 3 shows the use of the invention using coiled-tubingdrilling techniques.

Coiled Tubing Drilling

FIG. 3 shows another preferred embodiment of the invention that is usedfor certain types of coiled-tubing drilling applications. FIG. 3 showsmany elements common to FIG. 1. It is explicitly stated at this pointthat all the standard coiled-tubing drilling arts now practiced in theindustry are incorporated herein by reference. Not shown in FIG. 3 isthe coiled tubing drilling rig on the surface of the earth having amongother features, the coiled tubing unit, a source of mud, mud pump, etc.In FIG. 3, the well has been drilled. This well can be: (a) a freshlydrilled well; or (b) a well that has been sidetracked to a geologicalformation from within a casing string that is an existing cased wellduring standard re-entry applications; or (c) a well that has beensidetracked from within a tubing string that is in turn suspended withina casing string in an existing well during certain other types ofre-entry applications. Therefore, regardless of how drilling isinitially conducted, in an open hole, or from within a cased well thatmay or may not have a tubing string, the apparatus shown in FIG. 3drills a borehole 2 through the earth including through geologicalformation 4.

Before drilling commences, the lower end of the coiled tubing 104 isattached to the Latching Subassembly 18. The bottom male threads of thecoiled tubing 106 thread into the female threads of the LatchingSubassembly 50.

The top male threads 108 of the Stationary Mud Motor Assembly 110 arescrewed into the lower female threads 112 of Latching Subassembly 18.Mud under pressure flowing through channel 113 causes the Rotating MudMotor Assembly 114 to rotate in the well. The Rotating Mud MotorAssembly 114 causes the Mud Motor Drill Bit Body 116 to rotate. In apreferred embodiment, elements 110, 114 and 116 are elements comprisinga mud-motor drilling apparatus. That Mud Motor Drill Bit Body holds inplace milled steel roller cones 118, 120, and 122 (not shown forsimplicity). A standard water passage 124 is shown through the Mud MotorDrill Bit Body. During drilling operations, as mud is pumped down fromthe surface, the Rotating Mud Motor Assembly 114 rotates causing thedrilling action in the well. It should be noted that any fluid pumpedfrom the surface under sufficient pressure that passes through channel113 goes through the mud motor turbine (not shown) that causes therotation of the Mud Motor Drill Bit Body and then flows through standardwater passage 124 and finally into the well.

The steps for using the preferred embodiment in FIG. 3 are slightlydifferent than using that shown in FIG. 1. In drilling an open hole,“Steps 3-5 (Revised)” of the “New Drilling Process” must be revised hereto site attachment of the Latching Subassembly to one end of the coiledtubing and to site that standard coiled tubing drilling methods areemployed. The coiled tubing can be on the coiled tubing unit at thesurface for this step or the tubing can be installed into a wellhead onthe surface for this step. In “Step 6 (Revised)” of the “New DrillingProcess”, measurements are to be performed from within the coiled tubingwhen it is disposed in the well. In “Steps 12-13 (Revised)” of the “NewDrilling Process”, the Bottom Wiper Plug and the Top Wiper Plug areintroduced into the upper end of the coiled tubing at the surface. Thecoiled tubing can be on the coiled tubing unit at the surface for thesesteps or the tubing can be installed into a wellhead on the surface forthese steps. In sidetracking from within an existing casing, in additionto the above steps, it is also necessary to lower the coiled tubingdrilling apparatus into the cased well and drill through the casing intothe adjacent geological formation at some predetermined depth. Insidetracking from within an existing tubing string suspended within anexisting casing string, it is also necessary to lower the coiled tubingdrilling apparatus into the tubing string and then drill through thetubing string and then drill through the casing into the adjacentgeological formation at some predetermined depth.

Therefore, FIG. 3 shows a tubing conveyed mud motor drill bit apparatusto drill a borehole into the earth having a tubing attached to a mudmotor driven rotary drill bit. A one-way cement valve means installedabove the drill bit is used to cement the drill string and rotary drillbit into the earth to make a tubing encased well. The tubing conveyedmud motor drill bit apparatus is also called a tubing conveyed mud motordrilling apparatus, that is also called a tubing conveyed mud motordriven rotary drill bit apparatus. Put another way, FIG. 3 shows asection view of a coiled tubing conveyed mud motor driven rotary drillbit apparatus in the process of being cemented into place during onedrilling pass into formation. This apparatus is cemented into place byusing a Latching Float Collar Valve Assembly that has been pumped intoplace above the rotary drill bit. Methods of operating the tubingconveyed mud motor drilling apparatus in FIG. 3 include a method ofdrilling a borehole with a coiled tubing conveyed mud motor drivenrotary drill bit having mud passages to pass mud into the borehole fromwithin the tubing that includes at least one step that passes cementthrough the mud passages to cement the tubing into place to make atubing encased well.

In the “New Drilling Process”, Step 14 is to be repeated, and that stepis quoted in part in the following paragraph as follows:

-   -   ‘Step 14. Follow normal “final completion operations” that        include installing the tubing with packers and perforating the        casing near the producing zones. For a description of such        normal final completion operations, please refer to the book        entitled “Well Completion Methods”, Well Servicing and Workover,        Lesson 4, from the series entitled “Lessons in Well Servicing        and Workover”, Petroleum Extension Service, The University of        Texas at Austin, Austin, Tex., 1971 (hereinafter defined as        “Ref. 2”), an entire copy of which is incorporated herein by        reference. All of the individual definitions of words and        phrases in the Glossary of Ref. 2 are also explicitly and        separately incorporated herein in their entirety by reference.        Other methods of completing the well are described therein that        shall,    -   for the purposes of this application herein, also be called        “final completion operations”.’

With reference to the last sentence above, there are indeed many ‘Othermethods of completing the well that for the purposes of this applicationherein, also be called “final completion operations”’. For example, Ref.2 on pages 10-11 describe “Open-Hole Completions”. Ref. 2 on pages 13-17describe “Liner Completions”. Ref. 2 on pages 17-30 describe “PerforatedCasing Completions” that also includes descriptions of centralizers,squeeze cementing, single zone completions, multiple zone completions,tubingless completions, multiple tubingless completions, and deep wellliner completions among other topics.

Similar topics are also discussed in a previously referenced bookentitled “Testing and Completing”, Unit II, Lesson 5, Second Edition, ofthe Rotary Drilling Series, Petroleum Extension Service, The Universityof Texas at Austin, Austin, Tex., 1983 (hereinafter defined as “Ref.4”), an entire copy of which is incorporated herein by reference. All ofthe individual definitions of words and phrases in the Glossary of Ref.1 are also explicitly and separately incorporated herein in theirentirety by reference.

For example, on page 20 of Ref. 4, the topic “Completion Design” isdiscussed. Under this topic are described various different “CompletionMethods”. Page 21 of Ref. 4 describes “Open-hole completions”. Under thetopic of “Perforated completion” on pages 20-22, are described bothstandard cementing completions and gravel completions using slottedliners.

Well Completions with Slurry Materials

Standard cementing completions are described above in the new “NewDrilling Process”. However, it is evident that any slurry like materialor “slurry material” that flows under pressure, and behaves like amulticomponent viscous liquid like material, can be used instead of“cement” in the “New Drilling Process”. In particular, instead of“cement”, water, gravel, or any other material can be used provided itflows through pipes under suitable pressure.

At this point, it is useful to review several definitions that areroutinely used in the industry. First, the glossary of Ref. 4 definesseveral terms of interest.

The Glossary of Ref. 4 defines the term “to complete a well” to be thefollowing: “to finish work on a well and bring it to productive status.See well completion.”

The Glossary of Ref. 4 defines the term “well completion” to be thefollowing: “1. the activities and methods of preparing a well for theproduction of oil and gas; the method by which one or more flow pathsfor hydrocarbons is established between the reservoir and the surface.2. the systems of tubulars, packers, and other tools installed beneaththe wellhead in the production casing, that is, the tool assembly thatprovides the hydrocarbon flow path or paths.” To be precise for thepurposes herein, the term “completing a well” or the term “completingthe well” are each separately equivalent to performing all the necessarysteps for a “well completion”.

The Glossary of Ref. 4 defines the term “gravel” to be the following:“in gravel packing, sand or glass beads of uniform size and roundness.”

The Glossary of Ref. 4 defines the term “gravel packing” to be thefollowing: “a method of well completion in which a slotted or perforatedliner, often wire-wrapper, is placed in the well and surrounded bygravel. If open-hole, the well is sometimes enlarged by underreaming atthe point were the gravel is packed. The mass of gravel excludes sandfrom the wellbore but allows continued production.”

Other pertinent terms are defined in Ref. 1.

The Glossary of Ref. 1 defines the term “cement” to be the following: “apowder, consisting of alumina, silica, lime, and other substances thathardens when mixed with water. Extensively used in the oil industry tobond casing to walls of the wellbore.”

The Glossary of Ref. 1 defines the term “cement clinker” to be thefollowing: “a substance formed by melting ground limestone, clay orshale, and iron ore in a kiln. Cement clinker is ground into a powderymixture and combined with small accounts of gypsum or other materials toform a cement”.

The Glossary of Ref. 1 defines the term “slurry” to be the following: “aplastic mixture of cement and water that is pumped into a well toharden; there it supports the casing and provides a seal in the wellboreto prevent migration of underground fluids.”

The Glossary of Ref. 1 defines the term “casing” as is typically used inthe oil and gas industries to be the following: “steel pipe placed in anoil or gas well as drilling progresses to prevent the wall of the holefrom caving in during drilling, to prevent seepage of fluids, and toprovide a means of extracting petroleum if the well is productive”. Ofcourse, in light of the invention herein, the “drill pipe, becomes the“casing” . . . so the above definition needs modification under certainusages herein.

U.S. Pat. No. 4,883,125, that issued on Nov. 28, 1994, that is entitled“Cementing Oil and Gas Wells Using Converted Drilling Fluid”, an entirecopy of which is incorporated herein by reference, describes using “aquantity of drilling fluid mixed with a cement material and a dispersantsuch as a sulfonated styrene copolymer with or without an organic acid”.Such a “cement and copolymer mixture” is yet another example of a“slurry material” for the purposes herein.

U.S. Pat. No. 5,343,951, that issued on Sep. 6, 1994, that is entitled“Drilling and Cementing Slim Hole Wells”, an entire copy of which isincorporated herein by reference, describes “a drilling fluid comprisingblast furnace slag and water” that is subjected thereafter to anactivator that is “generally, an alkaline material and additional blastfurnace slag, to produce a cementitious slurry which is passed down acasing and up into an annulus to effect primary cementing.” Such an“blast furnace slag mixture” is yet another example of a “slurrymaterial” for the purposes herein.

Therefore, and in summary, a “slurry material”, may be any one, or more,of at least the following substances as rigorously defined above:cement, gravel, water, cement clinker, a “slurry” as rigorously definedabove, a “cement and copolymer mixture”, a “blast furnace slag mixture”,and/or any mixture thereof. Virtually any known substance that flowsunder sufficient pressure may be defined the purposes herein as a “slurry material”.

Therefore, in view of the above definitions, it is now evident that the“New Drilling Process” may be performed with any “slurry material”. Theslurry material may be used in the “New Drilling Process” for open-holewell completions; for typical cemented well completions havingperforated casings; and for gravel well completions having perforatedcasings; and for any other such well completions.

Accordingly, a preferred embodiment of the invention is the method ofdrilling a borehole with a rotary drill bit having mud passages forpassing mud into the borehole from within a steel drill string thatincludes at least the one step of passing a slurry material throughthose mud passages for the purpose of completing the well and leavingthe drill string in place to make a steel cased well.

Further, another preferred embodiment of the inventions is the method ofdrilling a borehole into a geological formation with a rotary drill bithaving mud passages for passing mud into the borehole from within asteel drill string that includes at least one step of passing a slurrymaterial through the mud passages for the purpose of completing the welland leaving the drill string in place following the well completion tomake a steel cased well during one drilling pass into the geologicalformation.

Yet further, another preferred embodiment of the invention is a methodof drilling a borehole with a coiled tubing conveyed mud motor drivenrotary drill bit having mud passages for passing mud into the boreholefrom within the tubing that includes at the least one step of passing aslurry material through the mud passages for the purpose of completingthe well and leaving the tubing in place to make a tubing encased well.

And further, yet another preferred embodiment of the invention is amethod of drilling a borehole into a geological formation with a coiledtubing conveyed mud motor driven rotary drill bit having mud passagesfor passing mud into the borehole from within the tubing that includesat least the one step of passing a slurry material through the mudpassages for the purpose of completing the well and leaving the tubingin place following the well completion to make a tubing encased wellduring one drilling pass into the geological formation.

Yet further, another preferred embodiment of the invention is a methodof drilling a borehole with a rotary drill bit having mud passages forpassing mud into the borehole from within a steel drill string thatincludes at least steps of: attaching a drill bit to the drill string;drilling the well with the rotary drill bit to a desired depth; andcompleting the well with the drill bit attached to the drill string tomake a steel cased well.

Still further, another preferred embodiment of the invention is a methodof drilling a borehole with a coiled tubing conveyed mud motor drivenrotary drill bit having mud passages for passing mud into the boreholefrom within the tubing that includes at least the steps of: attachingthe mud motor driven rotary drill bit to the coiled tubing; drilling thewell with the tubing conveyed mud motor driven rotary drill bit to adesired depth; and completing the well with the mud motor driven rotarydrill bit attached to the drill string to make a steel cased well.

And still further, another preferred embodiment of the invention is themethod of one pass drilling of a geological formation of interest toproduce hydrocarbons comprising at least the following steps: attachinga drill bit to a casing string; drilling a borehole into the earth to ageological formation of interest; providing a pathway for fluids toenter into the casing from the geological formation of interest;completing the well adjacent to the formation of interest with at leastone of cement, gravel, chemical ingredients, mud; and passing thehydrocarbons through the casing to the surface of the earth while thedrill bit remains attached to the casing.

The term “extended reach boreholes” is a term often used in the oil andgas industry. For example, this term is used in U.S. Pat. No. 5,343,950,that issued Sep. 6, 1994, having the Assignee of Shell Oil Company, thatis entitled “Drilling and Cementing Extended Reach Boreholes”. An entirecopy of U.S. Pat. No. 5,343,950 is incorporated herein by reference.This term can be applied to very deep wells, but most often is used todescribe those wells typically drilled and completed from offshoreplatforms. To be more explicit, those “extended reach boreholes” thatare completed from offshore platforms may also be called for thepurposes herein “extended reach lateral boreholes”. Often, thisparticular term, “extended reach lateral boreholes”, implies thatsubstantial portions of the wells have been completed in one more orless “horizontal formation”. The term “extended reach lateral borehole”is equivalent to the term “extended reach lateral wellbore” for thepurposes herein. The term “extended reach borehole” is equivalent to theterm “extended reach wellbore” for the purposes herein. The inventionherein is particularly useful to drill and complete “extended reachwellbores” and “extend reach lateral wellbores”.

Therefore, the preferred embodiments above generally disclose the onepass drilling and completion of wellbores with drill bit attached todrill string to make cased wellbores to produce hydrocarbons. Thepreferred embodiments above are also particularly useful to drill andcomplete “extended reach wellbores” and “extended reach lateralwellbores”.

For methods and apparatus particularly suitable for the one passdrilling and completion of extended reach lateral wellbores please referto FIG. 4. FIG. 4 shows another preferred embodiment of the inventionthat is closely related to FIG. 3. Those elements numbered in sequencethrough element number 124 have already been defined previously. In FIG.4, the previous single “Top Wiper Plug 64” in FIGS. 1, 2, and 3 has beenremoved, and instead, it has been replaced with two new wiper plugs,respectively called “Wiper Plug A” and “Wiper Plug B”. Wiper Plug A islabeled with numeral 126, and Wiper Plug A has a bottom surface that isdefined as the Bottom Surface of Wiper Plug A that is numeral 128. TheUpper Plug Seal of Wiper Plug A is labeled with numeral 130, and as itis shown in FIG. 4, is not ruptured. The Upper Plug Seal of Wiper Plug Athat is numeral 130 functions analogously to elements 54 and 56 of theUpper Seal of the Bottom Wiper Plug 52 that are shown in rupturedconditions in FIGS. 1, 2 and 3.

In FIG. 4, Wiper Plug B is labeled with numeral 132. It has a lowersurface that is called the “Bottom Surface of Wiper Plug B” that islabeled with numeral 134. Wiper Plug A and Wiper Plug B are introducedseparately into the interior of the tubing to pass multiple slurrymaterials into the wellbore to complete the well.

Using analogous methods described above in relation to FIGS. 1, 2, and3, water 136 in the tubing is used to push on Wiper Plug B (element132), that in turn pushes on cement 138 in the tubing, that in turn isused to push on gravel 140, that in turn pushes on the Float 32, that inturn forces gravel into the wellbore past Float 32, that in turn forcesmud 142 upward in the annulus of the wellbore. An explicit boundarybetween the mud and gravel is shown in the annulus of the wellbore inFIG. 4, and that boundary is labeled with numeral 144.

After the Bottom Surface of Wiper Plug A that is element 128 positively“bottoms out” on the Top Surface 74 of the Bottom Wiper Plug, then apredetermined amount of gravel has been injected into the wellboreforcing mud 142 upward in the annulus. Thereafter, forcing additionalwater 136 into the tubing will cause the Upper Plug Seal of Wiper Plug A(element 130) to rupture, thereby forcing cement 138 to flow toward theFloat 32. Forcing yet additional water 136 into the tubing will in turncause the Bottom Surface of Wiper Plug B 134 to “bottom out” on the TopSurface of Wiper Plug A that is labeled with numeral 146. At this pointin the process, mud has been forced upward in the annulus of wellbore bygravel. The purpose of this process is to have suitable amounts ofgravel and cement placed sequentially into the annulus between thewellbore for the completion of the tubing encased well and for theultimate production of oil and gas from the completed well. This processis particularly useful for the drilling and completion of extended reachlateral wellbores with a tubing conveyed mud motor drilling apparatus tomake tubing encased wellbores for the production of oil and gas.

It is clear that FIG. 1 could be modified with suitable Wiper Plugs Aand B as described above in relation to FIG. 4. Put simply, in light ofthe disclosure above, FIG. 4 could be suitably altered to show a rotarydrill bit attached to lengths of casing. However, in an effort to bebrief, that detail will not be further described. Instead, FIG. 5 showsone “snapshot” in the one pass drilling and completion of an extendedreach lateral wellbore with drill bit attached to the drill string thatis used to produce hydrocarbons from offshore platforms. This figure wassubstantially disclosed in U.S. Disclosure Document No. 452648 that wasfiled on Mar. 5, 1999.

Extended Reach Lateral Wellbores

In FIG. 5, An offshore platform 148 has a rotary drilling rig 150surrounded by ocean 152 that is attached to the bottom of the sea 154.Riser 156 is attached to blow-out preventer 158. Surface casing 160 iscemented into place with cement 162. Other conductor pipe, surfacecasing, intermediate casings, liner strings, or other pipes may bepresent, but are not shown for simplicity. The drilling rig 150 has alltypical components of a normal drilling rig as defined in the figureentitled “The Rig and its Components” opposite of page 1 of the bookentitled “The Rotary Rig and Its Components”, Third Edition, Unit I,Lesson 1, that is part of the “Rotary Drilling Series” published by thePetroleum Extension Service, Division of Continuing Education, TheUniversity of Texas at Austin, Austin, Tex., 1980, 39 pages, and entirecopy of which is incorporated herein by reference.

FIG. 5 shows that oil bearing formation 164 has been drilled into withrotary drill bit 166. Drill bit 166 is attached to a “Completion Sub”having the appropriate float collar valve assembly, or other suitablefloat collar device, or which has one or more suitable latch recessionssuch as element 24 in FIG. 1 for the purposes previously described, andwhich has other suitable completion devices as required that are shownin FIGS. 1, 2, 3, and 4. That “Completion Sub” is labeled with numeral168 in FIG. 5. Completion Sub 168 is in turn attached to many lengths ofdrill pipe, one of which is labeled with numeral 170 in FIG. 5. Thedrill pipe is supported by usual drilling apparatus provided by thedrilling rig. Such drilling apparatus provides an upward force at thesurface labeled with legend “F” in FIG. 5, and the drill string isturned with torque provided by the drilling apparatus of the drillingrig, and that torque is figuratively labeled with the legend “T” in FIG.5.

The previously described methods and apparatus were used to first, insequence, force gravel 172 in the portion of the oil bearing formation164 having producible hydrocarbons. If required, a cement plug formed bya “squeeze job” is figuratively shown by numeral 174 in FIG. 5 toprevent contamination of the gravel. Alternatively, an external casingpacker, or other types of controllable packer means may be used for suchpurposes as previously disclosed by applicant in U.S. DisclosureDocument No. 445686, filed on Oct. 11, 1998. Yet further, the cementplug 174 can be pumped into place ahead of the gravel using the aboveprocedures using yet another wiper plug as may be required.

The cement 176 introduced into the borehole through the mud passages ofthe drill bit using the above defined methods and apparatus provides aseal near the drill bit, among other locations, that is desirable undercertain situations.

Slots in the drill pipe have been opened after the drill pipe reachedfinal depth. The slots can be milled with a special milling cutterhaving thin rotating blades that are pushed against the inside of thepipe. As an alternative, standard perforations may be fabricated in thepipe using standard perforation guns of the type typically used in theindustry. Yet further, special types of expandable pipe may bemanufactured that when pressurized from the inside against a cement plugnear the drill bit or against a solid strong wiper plug, or against abridge plug, suitable slots are forced open. Or, different materials maybe used in solid slots along the length of steel pipe when the pipe isfabricated that can be etched out with acid during the well completionprocess to make the slots and otherwise leaving the remaining steel pipein place. Accordingly, there are many ways to make the required slots.One such slot is labeled with numeral 178 in FIG. 5, and there are manysuch slots.

Therefore, hydrocarbons in zone 164 are produced through gravel 172 thatflows through slots 178 and into the interior of the drill pipe toimplement the one pass drilling and completion of an extended reachlateral wellbore with drill bit attached to drill string to producehydrocarbons from an offshore platform. For the purposes of thispreferred embodiment, such a completion is called a “gravel pack”completion, whether or not cement 174 or cement 176 are introduced intothe wellbore.

It should be noted that in some embodiments, cement is not necessarilyneeded, and the formations may be “gravel pack” completed, or may beopen-hole completed. In some situations, the float, or the one-wayvalve, need not be required depending upon the pressures in theformation.

FIG. 5 also shows a zone that has been cemented shut with a “squeezejob”, a term known in the industry representing perforating and thenforcing cement into the annulus using suitable packers in order tocement certain formations. This particular cement introduced into theannulus of the wellbore in FIG. 5 is shown as element 180. Suchadditional cementations may be needed to isolate certain formations asis typically done in the industry. As a final comment, the annulus 182of the open hole 184 may otherwise be completed using typical wellcompletion procedures in the oil and gas industries.

Therefore, FIG. 5 and the above description discloses a preferred methodof drilling an extended reach lateral wellbore from an offshore platformwith a rotary drill bit having mud passages for passing mud into theborehole from within a steel drill string that includes at least onestep of passing a slurry material through the mud passages for thepurpose of completing the well and leaving the drill string in place tomake a steel cased well to produce hydrocarbons from the offshoreplatform. As stated before, the term “slurry material” may be any one,or more, of at least the following substances: cement, gravel, water,“cement clinker”, a “cement and copolymer mixture”, a “blast furnaceslag mixture”, and/or any mixture thereof; or any known substance thatflows under sufficient pressure.

Further, the above provides disclosure of a method of drilling anextended reach lateral wellbore from an offshore platform with a rotarydrill bit having mud passages for passing mud into the borehole fromwithin a steel drill string that includes at least the steps of passingsequentially in order a first slurry material and then a second slurrymaterial through the mud passages for the purpose of completing the welland leaving the drill string in place to make a steel cased well toproduce hydrocarbons from offshore platforms.

Yet another preferred embodiment of the invention provides a method ofdrilling an extended reach lateral wellbore from an offshore platformwith a rotary drill bit having mud passages for passing mud into theborehole from within a steel drill string that includes at least thestep of passing a multiplicity of slurry materials through the mudpassages for the purpose of completing the well and leaving the drillstring in place to make a steel cased well to produce hydrocarbons fromthe offshore platform.

It is evident from the disclosure in FIGS. 3 and 4, that a tubingconveyed mud motor drilling apparatus may replace the rotary drillingapparatus in FIG. 5. Consequently, the above has provided anotherpreferred embodiment of the invention that discloses the method ofdrilling an extended reach lateral wellbore from an offshore platformwith a coiled tubing conveyed mud motor driven rotary drill bit havingmud passages for passing mud into the borehole from within the tubingthat includes at least one step of passing a slurry material through themud passages for the purpose of completing the well and leaving thetubing in place to make a tubing encased well to produce hydrocarbonsfrom the offshore platform.

And yet further, another preferred embodiment of the invention providesa method of drilling an extended reach lateral wellbore from an offshoreplatform with a coiled tubing conveyed mud motor driven rotary drill bithaving mud passages for passing mud into the borehole from within thetubing that includes at least the steps of passing sequentially in ordera first slurry material and then a second slurry material through themud passages for the purpose of completing the well and leaving thetubing in place to make a tubing encased well to produce hydrocarbonsfrom the offshore platform.

And yet another preferred embodiment of the invention discloses passinga multiplicity of slurry materials through the mud passages of thetubing conveyed mud motor driven rotary drill bit to make a tubingencased well to produce hydrocarbons from the offshore platform.

For the purposes of this disclosure, any reference cited above isincorporated herein in its entirely by reference herein. Further, anydocument, article, or book cited in any such above defined reference isalso incorporated herein in its entirety by reference herein.

It should also be stated that the invention pertains to any type ofdrill bit having any conceivable type of passage way for mud that isattached to any conceivable type of drill pipe that drills to a depth ina geological formation wherein the drill bit is thereafter left at thedepth when the drilling stops and the well is completed. Any type ofdrilling apparatus that has at least one passage way for mud that isattached to any type of drill pipe is also an embodiment of thisinvention, where the drilling apparatus specifically includes any typeof rotary drill bit, any type of mud driven drill bit, any type ofhydraulically activated drill bit, or any type of electrically energizeddrill bit, or any drill bit that is any combination of the above. Anytype of drilling apparatus that has at least one passage way for mudthat is attached to any type of casing is also an embodiment of thisinvention, and this includes any metallic casing, any composite casing,and any plastic casing. Any type of drill bit attached to any type ofdrill pipe, or pipe, made from any material is an embodiment of thisinvention, where such pipe includes a metallic pipe; a casing string; acasing string with any retrievable drill bit removed from the wellbore;a casing string with any drilling apparatus removed from the wellbore; acasing string with any electrically operated drilling apparatusretrieved from the wellbore; a casing string with any bicenter bitremoved from the wellbore; a steel pipe; an expandable pipe; anexpandable pipe made from any material; an expandable metallic pipe; anexpandable metallic pipe with any retrievable drill bit removed from thewellbore; an expandable metallic pipe with any drilling apparatusremoved from the wellbore; an expandable metallic pipe with anyelectrically operated drilling apparatus retrieved from the wellbore; anexpandable metallic pipe with any bicenter bit removed from thewellbore; a plastic pipe; a fiberglass pipe; any type of composite pipe;any composite pipe that encapsulates insulated wires carryingelectricity and/or any tubes containing hydraulic fluid; a compositepipe with any retrievable drill bit removed from the wellbore; acomposite pipe with any drilling apparatus removed from the wellbore; acomposite pipe with any electrically operated drilling apparatusretrieved from the wellbore; a composite pipe with any bicenter bitremoved from the wellbore; a drill string; a drill string possessing adrill bit that remains attached to the end of the drill string aftercompleting the wellbore; a drill string with any retrievable drill bitremoved from the wellbore; a drill string with any drilling apparatusremoved from the wellbore; a drill string with any electrically operateddrilling apparatus retrieved from the wellbore; a drill string with anybicenter bit removed from the wellbore; a coiled tubing; a coiled tubingpossessing a mud-motor drilling apparatus that remains attached to thecoiled tubing after completing the wellbore; a coiled tubing left inplace after any mud-motor drilling apparatus has been removed; a coiledtubing left in place after any electrically operated drilling apparatushas been retrieved from the wellbore; a liner made from any material; aliner with any retrievable drill bit removed from the wellbore; a linerwith any liner drilling apparatus removed from the wellbore; a linerwith any electrically operated drilling apparatus retrieved from theliner; a liner with any bicenter bit removed from the wellbore; anyother pipe made of any material with any type of drilling apparatusremoved from the pipe; or any other pipe made of any material with anytype of drilling apparatus removed from the wellbore. Any drill bitattached to any drill pipe that remains at depth following wellcompletion is further an embodiment of this invention, and thisspecifically includes any retractable type drill bit, or retrievabletype drill bit, that because of failure, or choice, remains attached tothe drill string when the well is completed.

As had been referenced earlier, the above disclosure related to FIGS.1-5 had been substantially repeated herein from co-pending Ser. No.09/295,808, and this disclosure is used so that the new preferredembodiments of the invention can be economically described in terms ofthose figures. It should also be noted that the following disclosurerelated to FIGS. 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, and 18 isalso substantially repeated herein from co-pending Ser. No. 09/375,479.However, FIGS. 17A and 18A are figures that did not appear in Ser. No.09/375,479. FIGS. 19-26 have not appeared in any previous U.S. patentapplication although various embodiments have appeared in relevant U.S.Disclosure Documents.

Before describing those new features, perhaps a bit of nomenclatureshould be discussed at this point. In various descriptions of preferredembodiments herein described, inventor frequently uses the designationof “one pass drilling”, that is also called “One-Trip-Drilling” for thepurposes herein, and otherwise also called “One-Trip-Down-Drilling” forthe purposes herein. For the purposes herein, a first definition of thephrases “one pass drilling”, “One-Trip-Drilling”, and“One-Trip-Down-Drilling” mean the process that results in the last longpiece of pipe put in the wellbore to which a drill bit is attached isleft in place after total depth is reached, and is completed in place,and oil and gas is ultimately produced from within the wellbore throughthat long piece of pipe. Of course, other pipes, including risers,conductor pipes, surface casings, intermediate casings, etc., may bepresent, but the last very long pipe attached to the drill bit thatreaches the final depth is left in place and the well is completed usingthis first definition. This process is directed at dramatically reducingthe number of steps to drill and complete oil and gas wells.

Please note that several steps in the One-Trip-Down-Drilling process hadalready been finished in FIG. 5. However, it is instructive to take alook at one preferred method of well completion that leads to theconfiguration in FIG. 5. FIG. 6 shows one of the earlier steps in thatpreferred embodiment of well completion that leads to the configurationshown in FIG. 5. Further, FIG. 6 shows an embodiment of the inventionthat may be used with MWD/LWD measurements as described below.

Retrievable Instrumentation Packages

FIG. 6 shows an embodiment of the invention that is particularlyconfigured so that Measurement-While-Drilling (MWD) andLogging-While-Drilling (LWD) can be done during the drilling operations,but that following drilling operations employing MWD/LWD measurements,Smart Shuttles may be used thereafter to complete oil and gas productionfrom the offshore platform using procedures and apparatus described inthe following. Numerals 150 through 184 had been previously described inrelation to FIG. 5. In addition in FIG. 6, the last section of standarddrill pipe 186 is connected by threaded means to Smart Drilling andCompletion Sub 188, that in turn is connected by threaded means to BitAdaptor Sub 190, that is in turn connected by threaded means to rotarydrill bit 192. As an option, this drill bit may be chosen by theoperator to be a “Smart Bit” as described in the following.

The Smart Drilling and Completion Sub has provisions for many features.Many of these features are optional, so that some or all of them may beused during the drilling and completion of any one well. Many of thosefeatures are described in detail in U.S. Disclosure Document No. 452648filed on Mar. 5, 1999 that has been previously recited above. Inparticular, that U.S. Disclosure Document discloses the utility of“Retrievable Instrumentation Packages” that is described in detail inFIGS. 7 and 7A therein. Specifically, the preferred embodiment hereinprovides Smart Drilling and Completion Sub 188 that in turn surroundsthe Retrievable Instrumentation Package 194 as shown in FIG. 6.

As described in U.S. Disclosure Document No. 452648, to maximize thedrilling distance of extended reach lateral drilling, a preferredembodiment of the invention possess the option to have means to performmeasurements with sensors to sense drilling parameters, such asvibration, temperature, and lubrication flow in the drill bit—to namejust a few. The sensors may be put in the drill bit 192, and if any suchsensors are present, the bit is called a “Smart Bit” for the purposesherein. Suitable sensors to measure particular drilling parameters,particularly vibration, may also be placed in the RetrievableInstrumentation Package 194 in FIG. 6. So, the RetrievableInstrumentation Package 194 may have “drilling monitoringinstrumentation” that is an example of “drilling monitoringinstrumentation means”.

Any such measured information in FIG. 6 can be transmitted to thesurface. This can be done directly from the drill bit, or directly fromany locations in the drill string having suitable electronic receiversand transmitters (“repeaters”). As a particular example, the measuredinformation may be relayed from the Smart Bit to the RetrievableInstrumentation Package for final transmission to the surface. Anymeasured information in the Retrievable Instrumentation Package is alsosent to the surface from its transmitter. As set forth in the above U.S.Disclosure Documents No. 452648, an actuator in the drill bit in certainembodiments of the invention can be controlled from the surface that isanother optional feature of Smart Bit 192 in FIG. 6. If such an actuatoris in the drill bit, and/or if the drill bit has any type communicationmeans, then the bit is also called a Smart Bit for the purposes herein.As various options, commands could be sent directly to the drill bitfrom the surface or may be relayed from the Retrievable InstrumentationPackage to the drill bit. Therefore, the Retrievable InstrumentationPackage may have “drill bit control instrumentation” that is an exampleof a “drill bit control instrumentation means” which is used to controlsuch actuators in the drill bit.

In one preferred embodiment of the invention, commands sent to any SmartBit to change the configuration of the drill bit to optimize drillingparameters in FIG. 6 are sent from the surface to the RetrievableInstrumentation Package using a “first communication channel” which arein turn relayed by repeater means to the rotary drill bit 192 thatitself in this case is a “Smart Bit” using a “second communicationschannel”. Any other additional commands sent from the surface to theRetrievable Instrumentation Package could also be sent in that “firstcommunications channel”. As another preferred embodiment of theinvention, information sent from any Smart Bit that providesmeasurements during drilling to optimize drilling parameters can be sentfrom the Smart Bit to the Retrievable Instrumentation Package using a“third communications channel”, which are in turn relayed to the surfacefrom the Retrievable Instrumentation Package using a “fourthcommunication channel”. Any other information measured by theRetrievable Instrumentation Package such as directional drillinginformation and/or information from MWD/LWD measurements would also beadded to that fourth communications channel for simplicity. Ideally, thefirst, second, third, and fourth communications channels can sendinformation in real time simultaneously. Means to send informationincludes acoustic modulation means, electromagnetic means, etc., thatincludes any means typically used in the industry suitably adapted tomake the first, second, third, and fourth communications channels. Inprinciple, any number of communications channels “N” can be used, all ofwhich can be designed to function simultaneously. The above is onedescription of a “communications instrumentation”. Therefore, theRetrievable Instrumentation Package has “communications instrumentation”that is an example of “communications instrumentation means”.

In a preferred embodiment of the invention the RetrievableInstrumentation package includes a “directional assembly” meaning thatit possesses means to determine precisely the depth, orientation, andall typically required information about the location of the drill bitand the drill string during drilling operations. The “directionalassembly” may include accelerometers, magnetometers, gravitationalmeasurement devices, or any other means to determine the depth,orientation, and all other information that has been obtained duringtypical drilling operations. In principle this directional package canbe put in many locations in the drill string, but in a preferredembodiment of the invention, that information is provided by theRetrievable Instrumentation Package. Therefore, the RetrievableInstrumentation Package has a “directional measurement instrumentation”that is an example of a “directional measurement instrumentation means”.

As another option, and as another preferred embodiment, and means usedto control the directional drilling of the drill bit, or Smart Bit, inFIG. 6 can also be similarly incorporated in the RetrievableInstrumentation Package. Any hydraulic contacts necessary with formationcan be suitably fabricated into the exterior wall of the Smart Drillingand Completion Sub 188. Therefore, the Retrievable InstrumentationPackage may have “directional drilling control apparatus andinstrumentation” that is an example of “directional drilling controlapparatus and instrumentation means”.

As an option, and as a preferred embodiment of the invention, thecharacteristics of the geological formation can be measured using thedevice in FIG. 6. In principle, MWD (“Measurement-While-Drilling”) orLWD (“Logging-While-Drilling”) packages can be put in the drill stringat many locations. In a preferred embodiment shown in FIG. 6, the MWDand LWD electronics are made a part of the Retrievable InstrumentationPackage inside the Smart Drilling and Completion Sub 188. Not shown inFIG. 6, any sensors that require external contact with the formationsuch as electrodes to conduct electrical current into the formation,acoustic modulator windows to let sound out of the assembly, and otherspecial windows suitable for passing natural gamma rays, gamma rays fromspectral density tools, neutrons, etc., which are suitably incorporatedinto the exterior walls of the Smart Drilling and Completion Sub.Therefore, the Retrievable Instrumentation Package may have “MWD/LWDinstrumentation” that is an example of “MWD/LWD instrumentation means”.

Yet further, the Retrievable Instrumentation Package may also haveactive vibrational control devices. In this case, the “drillingmonitoring instrumentation” is used to control a feedback loop thatprovides a command via the “communications instrumentation” to anactuator in the Smart Bit that adjusts or changes bit parameters tooptimize drilling, and avoid “chattering”, etc. See the article entitled“Directional drilling performance improvement”, by M. Mims, World Oil,May 1999, pages 40-43, an entire copy of which is incorporated herein.Therefore, the Retrievable Instrumentation Package may also have “activefeedback control instrumentation and apparatus to optimize drillingparameters” that is an example of “active feedback and controlinstrumentation and apparatus means to optimize drilling parameters”.

Therefore, the Retrieval Instrumentation Package in the Smart Drillingand Completion Sub in FIG. 6 may have one or more of the followingelements:

-   -   (a) mechanical means to pass mud through the body of 188 to the        drill bit;    -   (b) retrieving means, including latching means, to accept and        align the Retrievable Instrumentation Package within the Smart        Drilling and Completion Sub;    -   (c) “drilling monitoring instrumentation” or “drilling        monitoring instrumentation means”;    -   (d) “drill bit control instrumentation” or “drill bit control        instrumentation means”;    -   (e) “communications instrumentation” or “communications        instrumentation means”;    -   (f) “directional measurement instrumentation” or “directional        measurement instrumentation means”;    -   (g) “directional drilling control apparatus and instrumentation”        or “directional drilling control apparatus and instrumentation        means”;    -   (h) “MWD/LWD instrumentation” or “MWD/LWD instrumentation means”        which provide typical geophysical measurements which include        induction measurements, laterolog measurements, resistivity        measurements, dielectric measurements, magnetic resonance        imaging measurements, neutron measurements, gamma ray        measurements; acoustic measurements, etc.    -   (i) “active feedback and control instrumentation and apparatus        to optimize drilling parameters” or “active feedback and control        instrumentation and apparatus means to optimize drilling        parameters”;    -   (j) an on-board power source in the Retrievable Instrumentation        Package or “on-board power source means in the Retrievable        Instrumentation Package”;    -   (k) an on-board mud-generator as is used in the industry to        provide energy to (j) above or “mud-generator means”.    -   (l) batteries as are used in the industry to provide energy        to (j) above or “battery means”;

For the purposes of this invention, any apparatus having one or more ofthe above features (a), (b) . . . , (j), (k), or (l), AND which can alsobe removed from the Smart Drilling and Completion Sub as described belowin relation to FIG. 7, shall be defined herein as a RetrievableInstrumentation Package, that is an example of a retrievable instrumentpackage means.

FIG. 7 shows a preferred embodiment of the invention that is explicitlyconfigured so that following drilling operations that employ MWD/LWDmeasurements of formation properties during those drilling operations,Smart Shuttles may be used thereafter to complete oil and gas productionfrom the offshore platform. As in FIG. 6, Smart Drilling and CompletionSub 188 has disposed inside it Retrievable Instrumentation Package 194.The Smart Drilling and Completion Sub has mud passage 196 through it.The Retrievable Instrumentation Package has mud passage 198 through it.The Smart Drilling and Completion Sub has upper threads 200 that engagethe last section of standard drill pipe 186 in FIG. 6. The SmartDrilling and Completion Sub has lower threads 202 that engage the upperthreads of the Bit Adaptor Sub 190 in FIG. 6.

In FIG. 7, the Retrievable Instrumentation Package has high pressurewalls 204 so that instrumentation in the package is not damaged bypressure in the wellbore. It has an inner payload radius r1, an outerpayload radius r2, and overall payload length L that are not shown forthe purposes of brevity. The Retrievable Instrumentation Package hasretrievable means 206 that allows a wireline conveyed device from thesurface to “lock on” and retrieve the Retrievable InstrumentationPackage. Element 206 is the “Retrieval Means Attached to the RetrievableInstrumentation Package”.

As shown in FIG. 7, the Retrievable Instrumentation Package may havelatching means 208 that is disposed in latch recession 210 that isactuated by latch actuator means 212. The latching means 208 and latchrecession 210 may function as described above in previous embodiments orthey may be electronically controlled as required from inside theRetrievable Instrumentation Package.

Guide recession 214 in the Smart Drilling and Completion Sub is used toguide into place the Retrievable Instrumentation Package havingalignment spur 216. These elements are used to guide the RetrievableInstrumentation Package into place and for other purposes as describedbelow. These are examples of “alignment means”.

Acoustic transmitter/receiver 218 and current conducting electrode 220are used to measure various geological parameters as is typical in theMWD/LWD art in the industry, and they are “potted” in insulatingrubber-like compounds 222 in the wall recession 224 shown in FIG. 7.Various MWD/LWD measurements are provided including inductionmeasurements, laterolog measurements, resistivity measurements,dielectric measurements, magnetic resonance imaging measurements,neutron measurements, gamma ray measurements; acoustic measurements,etc. Power and signals for acoustic transmitter/receiver 218 and currentconducting electrode 220 are sent over insulated wire bundles 226 and228 to mating electrical connectors 232 and 234. Electrical connector234 is a high pressure connector that provides power to the MWD/LWDsensors and brings their signals into the pressure free chamber withinthe Retrievable Instrumentation Package as are typically used in theindustry. Geometric plane “A” “B” is defined by those legends appearingin FIG. 7 for reasons which will be explained later.

A first directional drilling control apparatus and instrumentation isshown in FIG. 7. Cylindrical drilling guide 236 is attached by flexiblespring coupling device 238 to moving bearing 240 having fixed bearingrace 242 that is anchored to the housing of the Smart Drilling andCompletion Sub near the location specified by the numeral 244. Slidingblock 246 has bearing 248 that makes contact with the inner portion ofthe cylindrical drilling guide at the location specified by numeral 250that in turn sets the angle θ. The cylindrical drilling guide 236 isfree to spin when it is in physical contact with the geologicalformation. So, during rotary drilling, the cylindrical drilling guidespins about the axis of the Smart Drilling and Completion Sub that inturn rotates with the remainder of the drill string. The angle θ setsthe direction in the x-y plane of the drawing in FIG. 7. Sliding block246 is spring loaded with spring 252 in one direction (to the left inFIG. 7) and is acted upon by piston 254 in the opposite direction (tothe right as shown in FIG. 7). Piston 254 makes contact with the slidingblock at the position designated by numeral 256 in FIG. 7. Piston 254passes through bore 258 in the body of the Smart Drilling and CompletionSub and enters the Retrievable Instrumentation Package through o-ring260. Hydraulic piston actuator assembly 262 actuates the hydraulicpiston 254 under electronic control from instrumentation within theRetrievable Instrumentation Package as described below. The position ofthe cylindrical drilling guide 236 and its angle θ is held stable in thetwo dimensional plane specified in FIG. 7 by two competing forcesdescribed as (a) and (b) in the following: (a) the contact between theinner portion of the cylindrical drilling guide 236 and the bearing 248at the location specified by numeral 250; and (b) the net “return force”generated by the flexible spring coupling device 238. The return forcegenerated by the flexible spring coupling device is zero only when thecylindrical drilling guide 236 is parallel to the body of the SmartDrilling and Completion Sub.

There is a second such directional drilling control apparatus locatedrotationally 90 degrees from the first apparatus shown in FIG. 7 so thatthe drill bit can be properly guided in all directions for directionaldrilling purposes. However, this second assembly is not shown in FIG. 7for the purposes of brevity. This second assembly sets the angle θ inanalogy to the angle θ defined above. The directional drilling apparatusin FIG. 7 is one example of “directional drilling control means”.Directional drilling in the oil and gas industries is also frequentlycalled “geosteering”, particularly when geophysical information is usedin some way to direct the direction of drilling, and therefore theapparatus in FIG. 7 is also an example of a “geosteering means”.

For a general review of the status of developments on directionaldrilling control systems in the industry, and their related uses,particularly in offshore environments, please refer to the followingreferences: (a) the article entitled “ROTARY-STEERABLE TECHNOLOGY—Part1, Technology gains momentum”, by T. Warren, Oil and Gas Journal, Dec.21, 1998, pages 101-105, an entire copy of which is incorporated hereinby reference; (b) the article entitled “ROTARY-STEERABLETECHNOLOGY—Conclusion, Implementation issues concern operators”, by T.Warren, Oil and Gas Journal, Dec. 28, 1998, pages 80-83, an entire copyof which is incorporated herein by reference; (c) the entire issue ofWorld Oil dated December 1998 entitled in part on the front cover“Marine Drilling Rigs, What's Ahead in 1999”, an entire copy of which isincorporated herein by reference; (d) the entire issue of World Oildated July 1999 entitled in part on the front cover “Offshore Report”and “New Drilling Technology”, an entire copy of which is incorporatedherein in by reference; and (e) the entire issue of The American Oil andGas Reporter dated June 1999 entitled in part on the front cover“Offshore & Subsea Technology”, an entire copy of which is incorporatedherein by reference; (f) U.S. Pat. No. 5,332,048, having the inventorsof Underwood et. al., that issued on Jul. 26, 1994 entitled in part“Method and Apparatus for Automatic Closed Loop Drilling System”, anentire copy of which is incorporated herein by reference; (g) and U.S.Pat. No. 5,842,149 having the inventors of Harrell et. al., that issuedon Nov. 24, 1998, that is entitled “Closed Loop Drilling System”, anentire copy of which is incorporated herein by reference. Furthermore,all references cited in the above defined documents (a) and (b) and (c)and (d) and (e) and (f) and (g) in this paragraph are also incorporatedherein in their entirety by reference. Specifically, all 17 referencescited on page 105 of the article defined in (a) and all 3 referencescited on page 83 of the article defined in (b) are incorporated hereinby reference. For further reference, rotary steerable apparatus androtary steerable systems may also be called “rotary steerable means”, aterm defined herein. Further, all the terms that are used, or defined inthe above listed references (a), (b), (c), (d), and (e) are incorporatedherein in their entirety.

FIG. 7 also shows a mud-motor electrical generator. The mud-motorgenerator is only shown FIGURATIVELY in FIG. 7. This mud-motorelectrical generator is incorporated within the RetrievableInstrumentation Package so that the mud-motor electrical generator issubstantially removed when the Retrievable Instrumentation Package isremoved from the Smart Drilling and Completion Sub. Such a design can beimplemented using a split-generator design, where a permanent magnet isturned by mud flow, and pick-up coils inside the RetrievableInstrumentation Package are used to sense the changing magnetic fieldresulting in a voltage and current being generated. Such a design doesnot necessary need high pressure seals for turning shafts of themud-motor electrical generator itself. To figuratively show a preferredembodiment of the mud-motor electrical generator in FIG. 7, element 264is a permanently magnetized turbine blade having magnetic polarity N andS as shown. Element 266 is another such permanently magnetized turbineblade having similar magnetic polarity, but the N and S are not markedon element 266 in FIG. 7. These two turbine blades spin about a bearingat the position designated by numeral 268 where the two turbine bladescross in FIG. 7. The details for the support of that shaft are not shownin FIG. 7 for the purposes of brevity. The mud flowing through the mudpassage 198 of the Retrievable Instrumentation Package causes themagnetized turbine blades to spin about the bearing at position 268. Apick-up coil mounted on magnetic bar material designated by numeral 270senses the changing magnetic field caused by the spinning magnetizedturbine blades and produces electrical output 272 that in turn providestime varying voltage V(t) and time varying current I(t) to yet otherelectronics described below that is used to convert these waveforms intousable power as is required by the Retrievable Instrumentation Package.The changing magnetic field penetrates the high pressure walls 204 ofthe Retrievable Instrumentation Package. For the figurative embodimentof the mud-motor electrical generator shown in FIG. 7, non-magneticsteel walls are probably better to use than walls made of magneticmaterials. Therefore, the Retrievable Instrumentation Package and theSmart Drilling and Completion Sub may have a mud-motor electricalgenerator for the purposes herein.

The following block diagram elements are also shown in FIG. 7: element274, the electronic instrumentation to sense, accept, and align (orrelease) the “Retrieval Means Attached to the RetrievableInstrumentation Package” and to control the latch actuator means 212during acceptance (or release); element 276, “power source” such asbatteries and/or electronics to accept power from mud-motor electricalgenerator system and to generate and provide power as required to theremaining electronics and instrumentation in the RetrievableInstrumentation Package; element 278, “downhole computer” controllingvarious instrumentation and sensors that includes downhole computerapparatus that may include processors, software, volatile memories,non-volatile memories, data buses, analogue to digital converters asrequired, input/output devices as required, controllers, batteryback-ups, etc.; element 280, “communications instrumentation” as definedabove; element 282, “directional measurement instrumentation” as definedabove; element 284, “drilling monitoring instrumentation” as definedabove; element 286, “directional drilling control apparatus andinstrumentation” as defined above; element 288, “active feedback andcontrol instrumentation to optimize drilling parameters”, as definedabove; element 290, general purpose electronics and logic to make thesystem function properly including timing electronics, driverelectronics, computer interfacing, computer programs, processors, etc.;element 292, reserved for later use herein; and element 294 “MWD/LWDinstrumentation”, as defined above.

FIG. 7 also shows optional mud seal 296 on the outer portion of theRetrievable Instrumentation Package that prevents drilling mud fromflowing around the outer portion of that Package. Most of the drillingmud as shown in FIG. 7 flows through mud passages 196 and 198. Mud seal296 is shown figuratively only in FIG. 7, and may be a circular mudring, but any type of mud sealing element may be used, including thedesigns of elastomeric mud sealing elements normally associated withwiper plugs as described above and as used in the industry for a varietyof purposes.

It should be evident that the functions attributed to the single SmartDrilling and Completion Sub 188 and Retrievable Instrumentation Package194 may be arbitrarily assigned to any number of different subs anddifferent pressure housings as is typical in the industry. However,“breaking up” the Smart Drilling and Completion Sub and the RetrievableInstrumentation Package are only minor variations of the preferredembodiment described herein.

Perhaps it is also worth noting that a primary reason for inventing theRetrievable Instrumentation Package 194 is because in the event ofOne-Trip-Down-Drilling, then the drill bit and the Smart Drilling andCompletion Sub are left in the wellbore to save the time and effort tobring out the drill pipe and replace it with casing. However, if theMWD/LWD instrumentation is used as in FIG. 7, the electronics involvedis often considered too expensive to abandon in the wellbore. Further,major portions of the directional drilling control apparatus andinstrumentation and the mud-motor electrical generator are alsorelatively expensive, and those portions often need to be removed tominimize costs. Therefore, the Retrievable Instrumentation Package 194is retrieved from the wellbore before the well is thereafter completedto produce hydrocarbons.

The preferred embodiment of the invention in FIG. 7 has one particularvirtue that is of considerable value. When the RetrievableInstrumentation Package 194 is pulled to the left with the RetrievalMeans Attached to the Retrievable Instrumentation Package 206, thenmating connectors 232 and 234 disengage, and piston 254 is withdrawnthrough the bore 258 in the body of the Smart Drilling and CompletionSub. The piston 254 had made contact with the sliding block 246 at thelocation specified by numeral 256, and when the RetrievableInstrumentation Package 194 is withdrawn, the piston 254 is free to beremoved from the body of the Smart Drilling and Completion Sub. TheRetrievable Instrumentation Package “splits” from the Smart Drilling andCompletion Sub approximately along plane “A” “B” defined in FIG. 7. Inthis way, most of the important and expensive electronics andinstrumentation can be removed after the desired depth is reached. Withsuitable designs of the directional drilling control apparatus andinstrumentation, and with suitable designs of the mud-motor electricalgenerator, the most expensive portions of these components can beremoved with the Retrievable Instrumentation Package.

The preferred embodiment in FIG. 7 has yet another important virtue. Ifthere is any failure of the Retrievable Instrumentation Package beforethe desired depth has been reached, it can be replaced with another unitfrom the surface without removing the pipe from the well using methodsto be described in the following. This feature would save considerabletime and money that is required to “trip out” a standard drill string toreplace the functional features of the instrumentation now in theRetrievable Instrumentation Package.

In any event, after the total depth is reached in FIG. 6, and if theRetrievable Instrumentation Package had MWD and LWD measurement packagesas described in FIG. 7, then it is evident that sufficient geologicalinformation is available vs. depth to complete the well and to commencehydrocarbon production. Then, the Retrievable Instrumentation Packagecan be removed from the pipe using techniques to be described in thefollowing.

It should also be noted that in the event that the wellbore had beendrilled to the desired depth, but on the other hand, the MWD and LWDinformation had NOT been obtained from the Retrievable InstrumentationPackage during that drilling, and following its removal from the pipe,then measurements of the required geological formation properties canstill be obtained from within the steel pipe using the loggingtechniques described above under the topic of “Several Recent Changes inthe Industry”—and please refer to item (b) under that category. Loggingthrough steel pipes and logging through casings to obtain the requiredgeophysical information are now possible.

In any event, let us assume that at this point in theOne-Trip-Down-Drilling Process that the following is the situation: (a)the wellbore has been drilled to final depth; (b) the configuration isas shown in FIG. 6 with the Retrievable Instrumentation Package atdepth; and (c) complete geophysical information has been obtained withthe Retrievable Instrumentation Package.

As described earlier in relation to FIG. 7, the RetrievableInstrumentation Package has retrieval means 206 that allows a wirelineconveyed device operated from the surface to “lock on” and retrieve theRetrievable Instrumentation Package. Element 206 is the “Retrieval MeansAttached to the Retrievable Instrumentation Package” in FIG. 7. As oneform of the preferred embodiment shown in FIG. 7, element 206 may haveretrieval grove 298 that will assist the wireline conveyed device fromthe surface to “lock on” and retrieve the Retrievable InstrumentationPackage.

Smart Shuttles

FIG. 8 shows an example of such a wireline conveyed device operated fromthe surface of the earth used to retrieve devices within the steel drillpipe that is generally designated by numeral 300. A wireline 302,typically having 7 electrical conductors with an armor exterior, isattached to the cablehead, generally labeled with numeral 304 in FIG. 8.Cablehead 304 is in turn attached to the Smart Shuttle that is generallyshown as numeral 306 in FIG. 8, which in turn is connected to anattachment. In this case, the attachment is the “Retrieval &Installation Subassembly”, otherwise abbreviated as the“Retrieval/Installation Sub”, also simply abbreviated as the “RetrievalSub”, and it is generally shown as numeral 308 in FIG. 8. The SmartShuttle is used for a number of different purposes, but in the case ofFIG. 8, and in the sequence of events described in relation to FIGS. 6and 7, it is now appropriate to retrieve the Retrievable InstrumentationPackage installed in the drill string as shown in FIGS. 6 and 7. To thatend, please note that electronically controllable retrieval snap ringassembly 310 is designed to snap into the retrieval grove 298 of element206 when the mating nose 312 of the Retrieval Sub enters mud passage 198of the Retrievable Instrumentation Package. Mating nose 312 of theRetrieval Sub also has retrieval sub electrical connector 313 (not shownin FIG. 8) that provides electrical commands and electrical powerreceived from the wireline and from the Smart Shuttle as is appropriate.(For the record, the retrieval sub electrical connector 313 is not shownexplicitly in FIG. 8 because the scale of that drawing is too large, butelectrical connector 313 is explicitly shown in FIG. 9 where the scaleis appropriate.)

FIG. 8 shows a portion of an entire system to automatically complete oiland gas wells. This system is called the “Automated Smart Shuttle Oiland Gas Completion System”, or also abbreviated as the “Automated SmartShuttle System”, or the “Smart Shuttle Oil and Gas Completion System”.In FIG. 8, the floor of the offshore platform 314 is attached to riser156 having riser hanger apparatus 315 as is typically used in theindustry. The drill string 170 is composed of many lengths of drill pipeand a first blow-out preventer 316 is suitably installed on an uppersection of the drill pipe using typical art in the industry. This firstblow-out preventer 316 has automatic shut off apparatus 318 and manualback-up apparatus 319 as is typical in the industry. A top drill pipeflange 320 is installed on the top of the drill string.

The “Wiper Plug Pump-Down Stack” is generally shown as numeral 322 inFIG. 8. The reason for the name for this assembly will become clear inthe following. Wiper Plug Pump-Down Stack” 322 is comprised variouselements including the following: lower pump-down stack flange 324,cylindrical steel pipe wall 326, upper pump-down stack flange 328, firstinlet tube 330 with first inlet tube valve 332, second inlet tube 334with second inlet tube valve 336, third-inlet tube 338 with third inlettube valve 340, with primary injector tube 342 with primary injectortube valve 344. Particular regions within the “Wiper Plug Pump-DownStack” are identified respectively with legends A, B and C that areshown in FIG. 8. Bolts and bolt patterns for the lower pump-down stackflange 324, and its mating part that is top drill pipe flange 320, arenot shown for simplicity. Bolts and bolt patterns for the upper pumpdown stack flange 328, and its respective mating part to be describe inthe following, are also not shown for simplicity. In general in FIG. 8,flanges may have bolts and bolt patterns, but those are not necessarilyshown for the purposes of simplicity.

The “Smart Shuttle Chamber” 346 is generally shown in FIG. 8. SmartShuttle chamber door 348 is pressure sealed with a one-piece O-ringidentified with the numeral 350. That O-ring is in a standard O-ringgrove as is used in the industry. Bolt hole 352 through the SmartShuttle chamber door mates with mounting bolt hole 354 on the matingflange body 356 of the Smart Shuttle Chamber. Tightened bolts willfirmly hold the Smart Shuttle chamber door 348 against the mating flangebody 356 that will suitably compress the one-piece O-ring 350 to causethe Smart Shuttle Chamber to seal off any well pressure inside the SmartShuttle Chamber.

Smart Shuttle Chamber 346 also has first Smart Shuttle chamber inlettube 358 and first Smart Shuttle chamber inlet tube valve 360. SmartShuttle Chamber 346 also has second Smart Shuttle chamber inlet tube 362and second Smart Shuttle chamber inlet tube valve 364. Smart ShuttleChamber 346 has upper Smart Shuttle chamber cylindrical wall 366 andupper smart Shuttle Chamber flange 368 as shown in FIG. 8. The SmartShuttle Chamber 346 has two general regions identified with the legendsD and E in FIG. 8. Region D is the accessible region where accessoriesmay be attached or removed from the Smart Shuttle, and region E has acylindrical geometry below second Smart Shuttle chamber inlet tube 362.The Smart Shuttle and its attachments can be “pulled up” into region Efrom region D for various purposes to be described later. Smart ShuttleChamber 346 is attached by the lower Smart Shuttle flange 370 to upperpump-down stack flange 328. The entire assembly from the lower SmartShuttle flange 370 to the upper Smart Shuttle chamber flange 368 iscalled the “Smart Shuttle Chamber System” that is generally designatedwith the numeral 372 in FIG. 8. The Smart Shuttle Chamber System 372includes the Smart Shuttle Chamber itself that is numeral 346 which isalso referred to as region D in FIG. 8.

The “Wireline Lubricator System” 374 is also generally shown in FIG. 8.Bottom flange of wireline lubricator system 376 is designed to mate toupper Smart Shuttle chamber flange 368. These two flanges join at theposition marked by numeral 377. In FIG. 8, the legend Z shows the depthfrom this position 377 to the top of the Smart Shuttle. Measurement ofthis depth Z, and knowledge of the length L1 of the Smart Shuttle (notshown in FIG. 8 for simplicity), and the length L2 of the Retrieval Sub(not shown in FIG. 8 for simplicity), and all other pertinent lengthsL3, L4, . . . , of any apparatus in the wellbore, allows the calculationof the “depth to any particular element in the wellbore” using standardart in the industry.

The Wireline Lubricator System in FIG. 8 has various additionalfeatures, including a second blow-out preventer 378, lubricator top body380, fluid control pipe 382 and its fluid control valve 384, a hydraulicpacking gland generally designated by numeral 386 in FIG. 8, havinggland sealing apparatus 388, grease packing pipe 390 and grease packingvalve 392. Typical art in the industry is used to fabricate and operatethe Wireline Lubricator System, and for additional information on suchsystems, please refer to FIG. 9, page 11, of Lesson 4, entitled “WellCompletion Methods”, of series entitled “Lessons in Well Servicing andWorkover”, published by the Petroleum Extension Service of TheUniversity of Texas at Austin, Austin, Tex., 1971, that is incorporatedherein by reference in its entirety, which series was previouslyreferred to above as “Ref. 2”. In FIG. 8, the upper portion of thewireline 394 proceeds to sheaves as are used in the industry and to awireline drum under computer control as described in the following.However, at this point, it is necessary to further describe relevantattributes of the Smart Shuttle.

The Smart Shuttle shown as element 306 in FIG. 8 is an example of “aconveyance means”.

FIG. 9 shows an enlarged view of the Smart Shuttle 306 and the“Retrieval Sub” 308 that are attached to the cablehead 304 suspended bywireline 302. The cablehead has shear pins 396 as are typical in theindustry. A threaded quick change collar 398 causes the mating surfacesof the cablehead and the Smart Shuttle to join together at the locationspecified by numeral 400. Typically 7 insulated electrical conductorsare passed through the location specified by numeral 400 by suitableconnectors and O-rings as are used in the industry. Several of thesewires will supply the needed electrical energy to run the electricallyoperated pump in the Smart Shuttle and other devices as described below.

In FIG. 9, a particular embodiment of the Smart Shuttle is describedwhich, in this case, has an electrically operated internal pump, andthis pump is called the “internal pump of the Smart Shuttle” that isdesignated by numeral 402. Numeral 402 designates an “internal pumpmeans”. The upper inlet port 404 for the pump has electronicallycontrolled upper port valve 406. The lower inlet port 408 for the pumphas electronically controlled lower port valve 410. Also shown in FIG. 9is the bypass tube 412 having upper bypass tube valve 414 and lowerbypass tube valve 416. In a preferred embodiment of the invention, theelectrically operated internal pump 402 is a “positive displacementpump”. For such a pump, and if valves 406 and 410 are open, then duringany one specified time interval Δt, a specific volume of fluid ΔV1 ispumped from below the Smart Shuttle to above the Smart Shuttle throughinlets 404 and 408 as they are shown in FIG. 9. For further reference,the “down side” of the Smart Shuttle in FIG. 9 is the “first side” ofthe Smart Shuttle and the “up side” of the Smart Shuttle in FIG. 9 isthe “second side” of the Smart Shuttle. Such up and down designationsloose their meaning when the wellbore is substantially a horizontalwellbore where the Smart Shuttle will have great utility. Please referto the legends ΔV1 on FIG. 9. This volume ΔV1 relates to the movement ofthe Smart Shuttle as described later below.

In FIG. 9, the Smart Shuttle also has elastomer sealing elements. Theelastomer sealing elements on the right-hand side of FIG. 9 are labeledas elements 418 and 420. These elements are shown in a flexed statewhich are mechanically loaded against the right-hand interiorcylindrical wall 422 of the Smart Shuttle Chamber 346 by the hangingweight of the Smart Shuttle and related components. The elastomersealing elements on the left-hand side of FIG. 9 are labeled as elements424 and 426, and are shown in a relaxed state (horizontal) because theyare not in contact with any portion of a cylindrical wall of the SmartShuttle Chamber. These elastomer sealing elements are examples of“lateral sealing means” of the Smart Shuttle. In the preferredembodiment shown in FIG. 9, it is contemplated that the right-handelement 418 and the left-hand element 424 are portions of one singleelastomeric seal. It is further contemplated that the right-hand element420 and the left-hand element 426 are portions of yet another separateelastomeric seal. Many different seals are possible, and these areexamples of “sealing means” associated with the Smart Shuttle.

FIG. 9 further shows quick change collar 428 that causes the matingsurfaces of the lower portion of the Smart Shuttle to join together tothe upper mating surfaces of the Retrieval Sub at the location specifiedby numeral 430. Typically, 7 insulated electrical conductors are alsopassed through the location specified by numeral 430 by suitable matingelectrical connectors as are typically used in the industry. Therefore,power, control signals, and measurements can be relayed from the SmartShuttle to the Retrieval Sub and from the Retrieval Sub to the SmartShuttle by suitable mating electrical connectors at the locationspecified by numeral 430. To be thorough, it is probably worthwhile tonote here that numeral 431 is reserved to figuratively designate the topelectrical connector of the Retrieval Sub, although that connector 431is not shown in FIG. 9 for the purposes of simplicity. The position ofthe electronically controllable retrieval snap ring assembly 310 iscontrolled by signals from the Smart Shuttle. With no signal, the snapring of assembly 310 is spring-loaded into the position shown in FIG. 9.With a “release command” issued from the surface, electronicallycontrollable retrieval snap ring assembly 310 is retracted so that itdoes NOT protrude outside vertical surface 432 (i.e., snap ring assembly310 is in its full retracted position). Therefore, electronic signalsfrom the surface are used to control the electronically controllableretrieval snap ring assembly 310, and it may be commanded from thesurface to “release” whatever it had been holding in place. Inparticular, once suitably aligned, assembly 310 may be commanded to“engage” or “lock-on” retrieval grove 298 in the RetrievableInstrumentation Package 206, or it can be commanded to “release” or“pull back from” the retrieval grove 298 in the RetrievableInstrumentation Package as may be required during deployment orretrieval of that Package, as the case may be.

One method of operating the Smart Shuttle is as follows. With referenceto FIG. 8, and if the first Smart Shuttle chamber inlet tube valve 360is in its open position, fluids, such as water or drilling mud asrequired, are introduced into the first Smart Shuttle chamber inlet tube358. With second Smart Shuttle chamber inlet tube valve 364 in its openposition, then the injected fluids are allowed to escape through secondSmart Shuttle chamber inlet tube 362 until substantially all the air inthe system has been removed. In a preferred embodiment, the internalpump of the Smart Shuttle 402 is a self-priming pump, so that even ifany air remains, the pump will still pump fluid from below the SmartShuttle, to above the Smart Shuttle. Similarly, inlets 330, 334, 338,and 342, with their associated valves, can also be used to “bleed thesystem” to get rid of trapped air using typical procedures oftenassociated with hydraulic systems. With reference to FIG. 9, it wouldfurther help the situation if valves 406, 410, 414 and 416 in the SmartShuttle were all open simultaneously during “bleeding operations”,although this may not be necessary. The point is that using typicaltechniques in the industry, the entire volume within the regions A, B,C, D, and E within the interior of the apparatus in FIG. 8 can be fluidfilled with fluids such as drilling mud, water, etc. This state ofaffairs is called the “priming” of the Automated Smart Shuttle System inthis preferred embodiment of the invention.

After the Automated Smart Shuttle System is primed, then the wirelinedrum is operated to allow the Smart Shuttle and the Retrieval Sub to belowered from region D of FIG. 8 to the part of the system that includesregions A, B, and C. FIG. 10 shows the Smart Shuttle and Retrieval Subin that location.

The Smart Shuttle shown as element 306 in FIG. 9 is an example of “aconveyance means”.

In FIG. 10, all the numerals and legends in FIG. 10 have been previouslydefined. When the Smart Shuttle and the Retrieval Sub are located inregions A, B, and C, then the elastomer sealing elements 418, 420, 424,and 426 positively seal against the cylindrical walls of the now fluidfilled enclosure. Please notice the change in shape of the elastomersealing elements 424 and 426 in FIG. 9 and in FIG. 10. The reason forthis change is because the regions A, B, and C are bounded bycylindrical metal surfaces with intervening pipes such as inlet tubes330, 334, 338, and primary injector tube 342. In a preferred embodimentof the invention, the vertical distance between elastomeric units 418and 420 are chosen so that they do simultaneously overlap any two inletpipes to avoid loss a positive seal along the vertical extent of theSmart Shuttle.

Then, in FIG. 10, valves 414 and 416 are closed, and valves 406 and 410are opened. Thereafter, the electrically operated internal pump 402 isturned “on”. In a preferred embodiment of the invention, theelectrically operated internal pump is a “positive displacement pump”.For such a pump, and as had been previously described, during any onespecified time interval Δt, a specific volume of fluid ΔV1 is pumpedfrom below the Smart Shuttle to above the Smart Shuttle through valves406 and 410. Please refer to the legends ΔV1 on FIG. 10. In FIG. 10, Thetop of the Smart Shuttle is at depth Z, and that legend was defined inFIG. 8 in relation to position 377 in that figure. In FIG. 10, theinside radius of the cylindrical portion of the wellbore is defined bythe legend a1. However, first it is perhaps useful to describe severaldifferent embodiments of Smart Shuttles and associated Retrieval Subs.

Element 306 in FIG. 8 is the “Smart Shuttle”. This apparatus is “smart”because the “Smart Shuttle” has one or more of the following features(hereinafter, “List of Smart Shuttle Features”):

-   -   (a) it can provide depth measurement information, ie., it can        have “depth measurement means”    -   (b) it can provide orientation information within the metallic        pipe, drill string, or casing, whatever is appropriate,        including the angle with respect to vertical, and any azimuthal        angle in the pipe as required, and any other orientational        information required, ie., it can have “orientational        information measurement means”    -   (c) it can possess at least one power source, such as a battery        or batteries, or apparatus to convert electrical energy from the        wireline to power any sensors, electronics, computers, or        actuators as required, ie., it can have “power source means”    -   (d) it can possess at least one sensor and associated        electronics including any required analogue to digital converter        devices to monitor pressure, and/or temperature, such as        vibrational spectra, shock sensors, etc., ie., it can have        “sensor measurement means”    -   (e) it can receive commands sent from the surface, ie., it can        have “command receiver means from surface”    -   (f) it can send information to the surface, ie., it can have        “information transmission means to surface”    -   (g) it can relay information to one or more portions of the        drill string, ie., it can have “tool relay transmission means”    -   (h) it can receive information from one or more portions of the        drill string, ie., it can have “tool receiver means”    -   (i) it can have one or more means to process information, ie.,        it can have at least one “processor means”    -   (j) it can have one or more computers to process information,        and/or interpret commands, and/or send data, ie., it can have        one or more “computer means”    -   (k) it can have one or more means for data storage    -   (l) it can have one or more means for nonvolatile data storage        if power is interrupted, ie., it can have one or more        “nonvolatile data storage means”    -   (m) it can have one or more recording devices, ie., it can have        one or more “recording means”    -   (n) it can have one or more read only memories, ie., it can have        one or more “read only memory means”    -   (o) it can have one or more electronic controllers to process        information, ie., it can have one or more “electronic controller        means”    -   (p) it can have one or more actuator means to change at least        one physical element of the device in response to measurements        within the device, and/or commands received from the surface,        and/or relayed information from any portion of the drill string    -   (q) the device can be deployed into a pipe of any type including        a metallic pipe, a drill string, a composite pipe, a casing as        is appropriate, by any means, including means to pump it down        with mud pressure by analogy to a wiper plug, or it may use any        type of mechanical means including gears and wheels to engage        the casing, where such gears and wheels include any well tractor        type device, or it may have an electrically operated pump and a        seal, or it may be any type of “conveyance means”    -   (r) the device can be deployed with any coiled tubing device and        may be retrieved with any coiled tubing device, ie., it can be        deployed and retrieved with any “coiled tubing means”    -   (s) the device can be deployed with any coiled tubing device        having wireline inside the coiled tubing device    -   (t) the device can have “standard depth control sensors”, which        may also be called “standard geophysical depth control sensors”,        including natural gamma ray measurement devices, casing collar        locators, etc., ie., the device can have “standard depth control        measurement means”    -   (u) the device can have any typical geophysical measurement        device described in the art including its own MWD/LWD        measurement devices described elsewhere above, ie., it can have        any “geophysical measurement means”    -   (v) the device can have one or more electrically operated pumps        including positive displacement pumps, turbine pumps,        centrifugal pumps, impulse pumps, etc., ie., it can have one or        more “internal pump means”    -   (w) the device can have a positive displacement pump coupled to        a transmission device for providing relatively large pulling        forces, ie., it can have one or more “transmission means”    -   (x) the device can have two pumps in one unit, a positive        displacement pump to provide large forces and relatively slow        Smart Shuttle speeds and a turbine pump to provide lesser forces        at relatively high Smart Shuttle speeds, ie., it may have “two        or more internal pump means”    -   (y) the device can have one or more pumps operated by other        energy sources    -   (z) the device can have one or more bypass assemblies such as        the bypass assembly comprised of elements 464, 466, 468, 470,        and 472 in FIG. 11, ie., it may have one or more “bypass means”    -   (aa) the device can have one or more electrically operated        valves, ie., it can have one or more electrically operated        “valve means”    -   (ab) it can have attachments to it, or devices incorporated in        it, that install into the well and/or retrieve from the well        various “Well Completion Devices”that are defined below

As mentioned earlier, a U.S. Trademark Application has been filed forthe Mark “Smart Shuttle”. This Mark has received a “Notice ofPublication Under 12 (a)” and it will be published in the OfficialGazette on Jun. 11, 2002. Under “LISTING OF GOODS AND/OR SERVICES” forthe Mark “Smart Shuttle” it states: “oil and gas industry hydraulicallydriven or electrically driven conveyors to move equipment throughonshore and offshore wells, cased wells, open-hole wells, pipes,tubings, expandable tubings, liners, cylindrical sand screens, andproduction flowlines; the conveyed equipment including well completionand production devices, logging tools, perforating guns, well drillingequipment, coiled tubings for well stimulation, power cables, containersof chemicals, and flowline cleaning equipment”.

As mentioned earlier, a U.S. Trademark Application has been filed forthe Mark “Smart Shuttle”. This Mark has received a “Notice ofPublication Under 12(a)” and it will be published in the OfficialGazette on Jun. 11, 2002. The “LISTING OF GOODS AND/OR SERVICES” forMark “Well Locomotive” is the same as for “Smart Shuttle”.

The “Retrieval & Installation Subassembly”, otherwise abbreviated as the“Retrieval/Installation Sub”, also simply abbreviated as the “RetrievalSub”, which is generally shown as numeral 308, has one or more of thefollowing features (hereinafter, “List of Retrieval Sub Features”):

-   -   (a) it can be attached to, or is made a portion of, the Smart        Shuttle    -   (b) it can have means to retrieve apparatus disposed in a pipe        made of any material    -   (c) it can have means to install apparatus into a pipe made of        any material    -   (d) it can have means to install various completion devices into        a pipe made of any material    -   (e) it can have means to retrieve various completion devices        from a pipe made of any material    -   (f) it can have at least one sensor for measuring information        downhole, and apparatus for transmitting that measured        information to the Smart Shuttle or uphole, apparatus for        receiving commands if necessary, and a battery or batteries or        other suitable power source as may be required    -   (g) it can be attached to, or be made a portion of, a conveyance        means such as a well tractor    -   (h) it can be attached to, or be made a portion of, any        pump-down means of the types described later in this document

Element 402 that is the “internal pump of the Smart Shuttle” may be anyelectrically operated pump, or any hydraulically operated pump that inturn, derives its power in any way from the wireline. Standard art inthe field is used to fabricate the components of the Smart Shuttle andthat art includes all pump designs typically used in the industry.Standard literature on pumps, fluid mechanics, and hydraulics is alsoused to design and fabricate the components of the Smart Shuttle, andspecifically, the book entitled “Theory and Problems of Fluid Mechanicsand Hydraulics”, Third Edition, by R. V. Giles, J. B. Evett, and C. Liu,Schaum's Outline Series, McGraw-Hill, Inc., New York, N.Y., 1994, 378pages, is incorporated herein in its entirety by reference.

For the purposes of several preferred embodiments of this invention, anexample of a “wireline conveyed smart shuttle means having retrieval andinstallation means” (also “wireline conveyed Smart Shuttle means havingretrieval and installation means”) is comprised of the Smart Shuttle andthe Retrieval Sub shown in FIG. 8. From the above description, a SmartShuttle may have many different features that are defined in the above“List of Smart Shuttle Features” and the Smart Shuttle by itself iscalled for the purposes herein a “wireline conveyed smart shuttle means”(also “wireline conveyed Smart Shuttle means), or simply a “wirelineconveyed shuttle means”. A Retrieval Sub may have many differentfeatures that are defined in the above “List of Retrieval Sub Features”and for the purposes herein, it is also described as a “retrieval andinstallation means”. Accordingly, a particular preferred embodiment of a“wireline conveyed shuttle means” has one or more features from the“List of Smart Shuttle Features” and one or more features from the “Listof Retrieval Sub Features”. Therefore, any given “wireline conveyedshuttle means having retrieval and installation means” may have a vastnumber of different features as defined above. Depending upon thecontext, the definition of a “wireline conveyed smart shuttle meanshaving retrieval and installation means” may include any first number offeatures on the “List of Smart Shuttle Features” and may include anysecond number of features on the “List of Retrieval Sub Features”. Inthis context, and for example, a ”wireline conveyed shuttle means havingretrieval and installation means” may have 4 particular features on the“List of Smart Shuttle Features” and may have 3 features on the “List ofRetrieval Sub Features”. The phrase “wireline conveyed smart shuttlemeans having retrieval and installation means” is also equivalentlydescribed for the purposes herein as “wireline conveyed shuttle meanspossessing retrieval and installation means”.

It is now appropriate to discuss a generalized block diagram of one typeof Smart Shuttle. The block diagram of another preferred embodiment of aSmart Shuttle is identified as numeral 434 in FIG. 11. Legends showing“UP” and “DOWN” appear in FIG. 11. Element 436 represents a blockdiagram of a first electrically operated internal pump, and in thispreferred embodiment, it is a positive displacement pump, which isassociated with an upper port 438, electrically controlled upper valve440, upper tube 442, lower tube 444, electrically controlled lower valve446, and lower port 448, which subsystem is collectively called herein“the Positive Displacement Pump System”. In FIG. 11, there is anothersecond electrically operated internal pump, which in this case is anelectrically operated turbine pump 450, which is associated with anupper port 452, electrically operated upper valve 454, upper tube 456,lower tube 458, electrically operated lower valve 460, and lower port462, which system is collectively called herein “the Secondary PumpSystem”. FIG. 11 also shows upper bypass tube 464, electrically operatedupper bypass valve 466, connector tube 468, electrically operated lowerbypass valve 470, and lower bypass tube 472, which subsystem iscollectively called herein “the Bypass System”. The 7 conductors (plusarmor) from the cablehead are connected to upper electrical plug 473 inthe Smart Shuttle. The 7 conductors then proceed through the upperportion of the Smart Shuttle that are figuratively shown as numeral 474and those electrically insulated wires are connected to Smart Shuttleelectronics system module 476. The wire bundle pass through typicallyhaving 7 conductors that provide signals and power from the wireline andthe Smart Shuttle to the Retrieval Sub are figuratively shown as element478 and these in turn are connected to lower electrical connector 479.Signals and power from lower electrical connector 479 within the SmartShuttle are provided as necessary to mating top electrical connector 431of the Retrieval Sub and then those signals and power are in turn passedthrough the Retrieval Sub to the retrieval sub electrical connector 313as shown in FIG. 9. Smart Shuttle electronics system module 476 carriesout all the other possible functions listed as items (a) to (z), and(aa) to (ab), in the above defined list of “List of Smart ShuttleFeatures”, and those functions include all necessary electronics,computers, processors, measurement devices, etc. to carry out thefunctions of the Smart Shuttle. Various outputs from the Smart Shuttleelectronics system module 476 are figuratively shown as elements 480 to498. As an example, element 480 provides electrical energy to pump 436;element 482 provides electrical energy to pump 450; element 484 provideselectrical energy to valve 440; element 486 provides electrical energyto valve 446; element 488 provides electrical energy to valve 454;element 490 provides electrical energy to valve 460; element 492provides electrical energy to valve 466; element 494 provides electricalenergy to valve 470; etc. In the end, there may be a hundred or moreadditional electrical connections to and from the Smart Shuttleelectronics system module 476 that are collectively represented bynumerals 496 and 498. In FIG. 11, the right-hand and left-hand portionsof upper Smart Shuttle seal are labeled respectively 500 and 502.Further, the right-hand and left-hand portions of lower Smart Shuttleseal are labeled respectively with numerals 504 and 506. Not shown inFIG. 11 are apparatus that may be used to retract these seals underelectronic control that would protect the seals from wear during longtrips into the hole within mostly vertical well sections where theweight of the smart shuttle means (also “Smart Shuttle means”) issufficient to deploy it into the well under its own weight. These sealswould also be suitably retracted when the smart shuttle means is pulledup by the wireline.

The preferred embodiment of the block diagram for a Smart Shuttle has aparticular virtue. Electrically operated pump 450 is an electricallyoperated turbine pump, and when it is operating with valves 454 and 460open, and the rest closed, it can drag significant loads downhole atrelatively high speeds. However, when the well goes horizontal, theloads increase. If electrically operated pump 450 stalls or cavitates,etc., then electrically operated pump 436 that is a positivedisplacement pump takes over, and in this case, valves 440 and 446 areopen, with the rest closed. Pump 436 is a particular type of positivedisplacement pump that may be attached to a pump transmission device sothat the load presented to the positive displacement pump does notexceed some maximum specification independent of the external load. SeeFIG. 12 for additional details.

The Smart Shuttle shown as element 306 in FIG. 10 is an example of “aconveyance means”.

FIG. 12 shows a block diagram of a pump transmission device 508 thatprovides a mechanical drive 510 to positive displacement pump 512.Electrical power from the wireline is provided by wire bundle 514 toelectric motor 516 and that motor provides a mechanical coupling 518 topump transmission device 508. Pump transmission device 508 may be an“automatic pump transmission device” in analogy to the operation of anautomatic transmission in a vehicle, or pump transmission device 508 maybe a “standard pump transmission device” that has discrete mechanicalgear ratios that are under control from the surface of the earth. Such apump transmission device prevents pump stalling, and other pumpproblems, by matching the load seen by the pump to the power availableby the motor. Otherwise, the remaining block diagram for the systemwould resemble that shown in FIG. 11, but that is not shown here for thepurposes of brevity.

Another preferred embodiment of the Smart Shuttle contemplates using a“hybrid pump/wheel device”. In this approach, a particular hydraulicpump in the Smart Shuttle can be alternatively used to cause a tractionwheel to engage the interior of the pipe. In this hybrid approach, aparticular hydraulic pump in the Smart Shuttle is used in a first manneras is described in FIGS. 8-12. In this hybrid approach, and by using aset of electrically controlled valves, a particular hydraulic pump inthe Smart Shuttle is used in a second manner to cause a traction wheelto rotate and to engage the pipe that in turn causes the Smart Shuttleto translate within the pipe. There are many designs possible using this“hybrid approach”.

FIG. 13 shows a block diagram of a preferred embodiment of the SmartShuttle having a hybrid pump design that is generally designated withthe numeral 520. Selected elements ranging from element 436 to element506 in FIG. 13 have otherwise been defined in relation to FIG. 11. Inaddition, inlet port 522 is connected to electrically controlled valve524 that is in turn connected to two-state valve 526 that may becommanded from the surface of the earth to selectively switch betweentwo states as follows: “state 1”—the inlet port 522 is connected tosecondary pump tube 528 and the traction wheel tube 530 is closed; or“state 2”—the inlet port 522 is closed, and the secondary pump tube 528is connected to the traction wheel tube 530. Secondary pump tube 528 inturn is connected to second electrically operated pump 532, tube 534,electrically operated valve 536 and port 538 and operates analogously toelements 452-462 in FIG. 11 provided the two-state valve 526 is in state1.

In FIG. 13, in “state 2”, with valve 536 open, and when energized,electrically operated pump 532 forces well fluids through tube 528 andthrough two-state valve 526 and out tube 530. If valve 540 is open, thenthe fluids continue through tube 542 and to turbine assembly 544 thatcauses the traction wheel 546 to move the Smart Shuttle downward in thewell. In FIG. 13, the “turbine bypass tube” for fluids to be sent to thetop of the Smart Shuttle AFTER passage through turbine assembly 544 isNOT shown in detail for the purposes of simplicity only in FIG. 13, butthis “turbine bypass tube” is figuratively shown by dashed lines aselement 548.

In FIG. 13, the actuating apparatus causing the traction wheel 546 toengage the pipe on command from the surface is shown figuratively aselement 550 in FIG. 13. The point is that in “state 2”, fluids forcedthrough the turbine assembly 544 cause the traction wheel 546 to makethe Smart Shuttle go downward in the well, and during this process,fluids forced through the turbine assembly 544 are “vented” to the “up”side of the Smart Shuttle through “turbine bypass tube” 548. Backingrollers 552 and 554 are figuratively shown in FIG. 13, and these rollerstake side thrust against the pipe when the traction wheel 546 engagesthe inside of the pipe.

In the event that seals 500-502 or 504-506 in FIG. 13 were to losehydraulic sealing with the pipe, then “state 2” provides yet anothermeans to cause the Smart Shuttle to go downward in the well undercontrol from the surface. The wireline can provide arbitrary pull in thevertical direction, so in this preferred embodiment, “state 2” isprimarily directed at making the Smart Shuttle go downward in the wellunder command from the surface. Therefore, in FIG. 13, there are a totalof three independent ways to make the Smart Shuttle go downward undercommand from the surface of the earth (“standard” use of pump 436;“standard” use of pump 532 in “state 1”; and the use of the tractionwheel in “state 2”).

The “hybrid pump/wheel device” that is an embodiment of the SmartShuttle shown in FIG. 13 is yet another example of “a conveyance means”.

The downward velocity of the Smart Shuttle can be easily determinedassuming that electrically operated pump 402 in FIGS. 9 and 10 arepositive displacement pumps so that there is no “pump slippage” causedby pump stalling, cavitation effects, or other pump “imperfections”. Thefollowing also applies to any pump that pumps a given volume per unittime without any such non-ideal effects. As stated before, in the timeinterval Δt, a quantity of fluid ΔV1 is pumped from below the SmartShuttle to above it. Therefore, if the position of the Smart Shuttlechanges downward by AZ in the time interval Δt, and with radius a1defined in FIG. 10, it is evident that:

ΔV1/Δt=ΔZ/Δt{π(a1)²}  Equation 1. $\quad\begin{matrix}\begin{matrix}{{{Downward}\quad{Velocity}} = {\Delta\quad{Z/\Delta}\quad t}} \\{= {\left\{ {\Delta\quad{{V1}/\Delta}\quad t} \right\}/{\left\{ {\pi({al})}^{2} \right\}.}}}\end{matrix} & {{Equation}\quad 2}\end{matrix}$

Here, the “Downward Velocity” defined in Equation 2 is the averagedownward velocity of the Smart Shuttle that is averaged over many cyclesof the pump. After the Smart Shuttle of the Automated Smart ShuttleSystem is primed, then the Smart Shuttle and its pump resides in astanding fluid column and the fluids are relatively non-compressible.Further, with the above pump transmission device 508 in FIG. 12, orequivalent, the electrically operated pump system will not stall.Therefore, when a given volume of fluid ΔV is pumped from below theSmart Shuttle to above it, the Shuttle will move downward provided theelastomeric seals like elements 500, 502, 504 and 506 in FIGS. 9, 11,and 13 do not lose hydraulic seal with the casing. Again there are manydesigns for such seals, and of course, more than two seals can be usedalong the length of the Smart Shuttle. If the seals momentarily loosetheir hydraulic sealing ability, then a “hybrid pump/wheel device” asdescribed in FIG. 13 can be used momentarily until the seals again makesuitable contact with the interior of the pipe.

The preferred embodiment of the Smart Shuttle having internal pump meansto pump fluid from below the Smart Shuttle to above it to cause theshuttle to move in the pipe may also be used to replace relatively slowand relatively inefficient “well tractors” that are now commonly used inthe industry.

Closed-Loop Completion System

FIG. 14 shows a remaining component of the Automated Smart ShuttleSystem. It is a portion of a preferred embodiment of an automated systemto complete oil and gas wells. It is also a portion of a preferredembodiment of a closed-loop system to complete oil and gas wells. FIG.14 shows the computer control of the wireline drum and of the SmartShuttle in a preferred embodiment of the invention.

In FIG. 14, computer system 556 has typical components in the industryincluding one or more processors, one or more non-volatile memories, oneor more volatile memories, many software programs that can runconcurrently or alternatively as the situation requires, etc., and allother features as necessary to provide computer control of the AutomatedShuttle System. In this preferred embodiment, this same computer system556 also has the capability to acquire data from, send commands to, andotherwise properly operate and control all instruments in theRetrievable Instrumentation Package. Therefore LWD and MWD data isacquired by this same computer system when appropriate. Therefore, inone preferred embodiment, the computer system 556 has all necessarycomponents to interact with the Retrievable Instrumentation Package. Ina “closed-loop” operation of the system, information obtained downholefrom the Retrievable Instrumentation Package is sent to the computersystem that is executing a series of programmed steps, whereby thosesteps may be changed or altered depending upon the information receivedfrom the downhole sensor.

In FIG. 14, the computer system 556 has a cable 558 that connects it todisplay console 560. The display console 560 displays data, programsteps, and any information required to operate the Smart Shuttle System.The display console is also connected via cable 562 to alarm andcommunications system 564 that provides proper notification to crewsthat servicing is required—particularly if the Smart Shuttle chamber 346in FIG. 8 needs servicing that in turn generally involves changingvarious devices connected to the Smart Shuttle. Data entry andprogramming console 566 provides means to enter any required digital ormanual data, commands, or software as needed by the computer system, andit is connected to the computer system via cable 568.

In FIG. 14, computer system 556 provides commands over cable 570 to theelectronics interfacing system 572 that has many functions. One functionof the electronics interfacing system is to provide information to andfrom the Smart Shuttle through cabling 574 that is connected to theslip-ring 576, as is typically used in the industry. The slip-ring 576is suitably mounted on the side of the wireline drum 578 in FIG. 14.Information provided to slip-ring 576 then proceeds to wireline 580 thatgenerally has 7 electrical conductors enclosed in armor. That wireline580 proceeds to overhead sheave 582 that is suitably suspended above theWireline Lubricator System in FIG. 8. In particular, the lower portionof the wireline 394 shown in FIG. 14 is also shown as the top portion ofthe wireline 394 that enters the Wireline Lubricator System in FIG. 8.That particular portion of the wireline 394 is the same in FIG. 14 andin FIG. 8, and this equality provides a logical connection between thesetwo figures.

In FIG. 14, electronics interfacing system 572 also provides power andelectronic control of the wireline drum hydraulic motor and pumpassembly 584 as is typically used in the industry today (that replacedearlier chain drive systems). Wireline drum hydraulic motor and pumpassembly 584 controls the motion of the wireline drum, and when it windsup in the counter-clockwise direction as observed in FIG. 14, the SmartShuttle goes upwards in the wellbore in FIG. 8, and Z decreases.Similarly, when the wireline drum hydraulic motor and pump assembly 584provides motion in the clockwise direction as observed in FIG. 14, thenthe Smart Shuttle goes down in FIG. 8 and Z increases. The wireline drumhydraulic motor and pump assembly 584 is connected to cable connector588 that is in turn connected to cabling 590 that is in turn connectedto electronics interfacing system 572 that is in turn controlled bycomputer system 556. Electronics interfacing system 572 also providespower and electronic control of any coiled tubing rig designated byelement 591 (not shown in FIG. 14), including the coiled tubing drumhydraulic motor and pump assembly of that coiled tubing rig, but such acoiled tubing rig is not shown in FIG. 14 for the purposes ofsimplicity. In addition, electronics interfacing system 572 has outputcable 592 that provides commands and control to drilling rig hardwarecontrol system 594 that controls various drilling rig functions andapparatus including the rotary drilling table motors, the mud pumpmotors, the pumps that control cement flow and other slurry materials asrequired, and all electronically controlled valves, and those functionsare controlled through cable bundle 596 which has an arrow on it in FIG.14 to indicate that this cabling goes to these enumerated items.

In relation to FIG. 14, a preferred embodiment of a portion of theAutomated Smart Shuttle System shown in FIG. 8 has electronicallycontrolled valves, so that valves 392, 384, 378, 364, 360, 344, 340,336, 332, and 316 as seen from top to bottom in FIG. 8, and are allelectronically controlled in this embodiment, and may be opened or shutremotely from drilling rig hardware control system 594. In addition,electronics interfacing system 572 also has cable output 598 toancillary surface transducer and communications control system 600 thatprovides any required surface transducers and/or communications devicesrequired for the instrumentation within the Retrievable InstrumentationPackage. In a preferred embodiment, ancillary surface and communicationssystem 600 provides acoustic transmitters and acoustic receivers as maybe required to communicate to and from the Retrievable InstrumentationPackage. The ancillary surface and communications system 600 isconnected to the required transducers, etc. by cabling 602 that has anarrow in FIG. 14 designating that this cabling proceeds to thoseenumerated transducers and other devices as may be required.

With respect to FIG. 14, and to the closed-loop system to complete oiland gas wells, standard electronic feedback control systems and designsare used to implement the entire system as described above, includingthose described in the book entitled “Theory and Problems of Feedbackand Control Systems”, “Second Edition”, “Continuous(Analog) andDiscrete(Digital)”, by J. J. DiStefano III, A. R. Stubberud, and I. J.Williams, Schaum's Outline Series, McGraw-Hill, Inc., New York, N.Y.,1990, 512 pages, an entire copy of which is incorporated herein byreference. Therefore, in FIG. 14, the computer system 556 has theability to communicate with, and to control, all of the above enumerateddevices and functions that have been described in this paragraph.

To emphasize one major point in FIG. 14, computer system 556 has theability to receive information from one or more downhole sensors for theclosed-loop system to complete oil and gas wells. This computer systemexecutes a sequence of programmed steps, but those steps may depend uponinformation obtained from at least one sensor located within thewellbore.

The entire system represented in FIG. 14 provides the automation for the“Automated Smart Shuttle Oil and Gas Completion System”, or alsoabbreviated as the “Automated Smart Shuttle System”, or the “SmartShuttle Oil and Gas Completion System”. The system in FIG. 14 is the“automatic control means” for the “wireline conveyed shuttle meanshaving retrieval and installation means” (also wireline conveyed SmartShuttle means having retrieval and installation means”), or simply the“automatic control means” for the “smart shuttle means” (also “SmartShuttle means”).

Steps to Complete Well Shown in FIG. 6

The following describes the completion of one well commencing with thewell diagram shown in FIG. 6. In FIG. 6, it is assumed that the well hasbeen drilled to total depth. Furthermore, it is also assumed here thatall geophysical information is known about the geological formationbecause the embodiment of the Retrievable Instrumentation Package shownin FIG. 6 has provided complete LWD/MWD information.

The first step is to disconnect the top of the drill string 170 in FIG.6 from the drilling rig apparatus. In this step, the kelly, etc. isdisconnected and removed from the drill string that is otherwise held inplace with slips as necessary until the next step.

In addition to typical well control procedures, the second step is toattach to the top of that drill pipe first blow-out preventer 316 andtop drill pipe flange 320 as shown in FIG. 8, and to otherwise attach tothat flange 320 various portions of the Automated Smart Shuttle Systemshown in FIG. 8 including the “Wiper Plug Pump-Down Stack” 322, the“Smart Shuttle Chamber” 346, and the “Wireline Lubricator System” 374,which are subassemblies that are shown in their final positions afterassembly in FIG. 8.

The third step is the “priming” of the Automated Smart Shuttle System asdescribed in relation to FIG. 8.

The fourth step is to retrieve the Retrievable Instrumentation Package.Please recall that the Retrievable Instrumentation Package hasheretofore provided all information about the wellbore, including thedepth, geophysical parameters, etc. Therefore, computer system 556 inFIG. 14 already has this information in its memory and is available forother programs. “Program A” of the computer system 556 is instigatedthat automatically sends the Smart Shuttle 306 and its Retrieval Sub 308(see FIG. 9) down into the drill string, and causes the electronicallycontrollable retrieval snap ring assembly 310 in FIG. 9 to positivelysnap into the retrieval grove 298 of element 206 of the RetrievableInstrumentation Package in FIG. 7 when the mating nose 312 of theRetrieval Sub in FIG. 9 enters mud passage 198 of the RetrievableInstrumentation Package in FIG. 7. Thereafter, the Retrieval Sub has“latched onto” the Retrievable Instrumentation Package. Thereafter, acommand is given by the computer system that pulls up on the wirelinethereby disengaging mating electrical connectors 232 and 234 in FIG. 7,and pulling piston 254 through bore 258 in the body of the SmartDrilling and Completion Sub in FIG. 7. Thereafter, the Smart Shuttle,the Retrieval Sub, and the Retrievable Instrumentation Package underautomatic control of “Program A” return to the surface as one unit.Thereafter, “Program A” causes the Smart Shuttle and the Retrieval Subto “park” the Retrievable Instrumentation Package within the “SmartShuttle Chamber” 346 and adjacent to the Smart Shuttle chamber door 348.Thereafter, the alarm and communications system 564 sounds a suitable“alarm” to the crew that servicing is required—in this case theRetrievable Instrumentation Package needs to be retrieved from the SmartShuttle Chamber. The fourth step is completed when the RetrievableInstrumentation Package is removed from the Smart Shuttle Chamber. As analternative, an automated “hopper system” under control of the computersystem can replace the functions of the servicing crew therefore makingthis portion of the completion an entirely automated process or as apart of a closed-loop system to complete oil and gas wells.

The fifth step is to pump down cement and gravel using a suitablepump-down latching one-way valve means and a series of wiper plugs toprepare the bottom portion of the drill string for the final completionsteps. The procedure here is followed in analogy with those described inrelation to FIGS. 1-4 above. Here, however, the pump-down latchingone-way valve means that is similar to the Latching Float Collar ValveAssembly 20 in FIG. 1 is also fitted with apparatus attached to itsUpper Seal 22 that provides similar apparatus and function to element206 of the Retrievable Instrumentation Package in FIG. 7. Put simply, adevice similar to the Latching Float Collar Valve Assembly 20 in FIG. 1is fitted with additional apparatus so that it may be convenientlydeployed in the well by the Retrieval Sub. Wiper plugs are similarlyfitted with such apparatus so that they can also be deployed in the wellby the Retrieval Sub. As an example of such fitted apparatus, wiperplugs are fabricated that have rubber attachment features so that theycan be mated to the Retrieval Sub in the Smart Shuttle Chamber. A crosssection of such a rubber-type material wiper plug is generally shown aselement 604 in FIG. 15; which has upper wiper attachment apparatus 606that provides similar apparatus and function to element 206 of theRetrievable Instrumentation Package in FIG. 7; and which has flexibleupper wiper blade 608 to fit the interior of the pipe present; flexiblelower wiper blade 610 to fit the interior of the pipe present; wiperplug indentation region between the blades specified by numeral 612;wiper plug interior recession region 614; and wiper plug perforationwall 616 that perforates under suitable applied pressure; and where insome forms of the wiper plugs called “solid wiper plugs”, there is nosuch wiper plug interior recession region and no portion of the plugwall can be perforated; and where the legends of “UP” and “DOWN” arealso shown in FIG. 15. In part because the wiper plug shown in FIG. 15may be conveyed downhole with the Retrieval Sub, it is an example of a“smart wiper plug”. Further, this smart wiper plug may also possess oneor more downhole sensors that provides information to the computersystem that controls the well completion process. Accordingly, apump-down latching one-way valve means is attached to the Retrieval Subin the Smart Shuttle Chamber, and the computer system is operated using“Program B”, where the pump-down latching one-way valve means is placedat, and is released in the pipe adjacent to riser hanger apparatus 315in FIG. 8. Then, under “Program B”, perforable wiper plug #1 is attachedto the Retrieval Sub in the Smart Shuttle Chamber, and it is placed atand released adjacent to region A in FIG. 8. Not shown in FIG. 8 areoptional controllable “wiper holding apparatus” that on suitablecommands fit into the wiper plug indentation region 612 and temporallyhold the wiper plug in place within the pipe in FIG. 8. Then under“Program B”, perforable wiper plug #2 is attached to the Retrieval Subin the Smart Shuttle Chamber, and it is placed at and released adjacentto region B in FIG. 8. Then under “Program B”, solid wiper plug #3 isattached to the Retrieval Sub in the Smart Shuttle Chamber, and it isplaced at and released adjacent to region C in FIG. 8, and the SmartShuttle and the Retrieval Sub are “parked” in region E of the SmartShuttle Chamber in FIG. 8. Then the Smart Shuttle Chamber is closed, andthe chamber itself is suitably “primed” with well fluids. Then, withother valves closed, valve 332 is the opened, and “first volume ofcement” is pumped into the pipe forcing the pump-down latching one-wayvalve means to be forced downward. Then valve 332 is closed, and valve336 is opened, and a predetermined volume of gravel is forced into thepipe that in turn forces wiper plug #1 and the one-way valve meansdownward. Then, valve 336 is closed, and valve 338 opened, and a “secondvolume of cement” is pumped into the pipe forcing wiper plugs #1 and #2and the one-way valve means downward. Then valve #338 is closed, andvalve 344 is opened, and water is injected into the system forcing wiperplugs #1, #2, and #3, and the one-way valve means downward. Then thelatching apparatus of the pump-down latching one-way valve meansappropriately seats in latch recession 210 of the Smart Drilling andCompletion Sub in FIG. 8 that was previously used to latch into placethe Retrievable Instrumentation Package. From this disclosure, thepump-down latching one-way valve means has latching means resemblingelement 208 of the Retrievable Instrumentation Package so that it canlatch into place in latch recession 210 of the Smart Drilling andCompletion Sub. In the end, the sequential charges of cement, gravel,and then cement are forced through the respective perforated wiper plugsand the one-way valve means and through the mud passages in the drillbit and into the annulus between the drill pipe and the wellbore. Valve344 is then closed, and pressure is then released in the drill pipe, andthe one-way valve means allows the first and second volumes of cement toset up properly on the outside of the drill pipe. After “Program B” iscompleted, the communications system 564 sounds a suitable “alarm” thatthe next step should be taken to complete the well. As previouslydescribed, an automated “hopper system” under control of the computersystem can load the requirement devices into the Smart Shuttle Chamber,and can also suitably control all valves, pumps, etc. so as to make thisa completed automated procedure, or as part of a closed-loop system tocomplete oil and gas wells.

The sixth step is to saw slots in the drill pipe similar to the slotthat is labeled with numeral 178 in FIG. 5. Accordingly, a “Casing Saw”is fitted so that it can be attached to and deployed by the RetrievalSub. This Casing Saw is figuratively shown in FIG. 16 as element 618.The Casing Saw 618 has upper attachment apparatus 620 that providessimilar apparatus and mechanical functions as provided by element 206 ofthe Retrievable Instrumentation Package in FIG. 7—but, that in addition,it also has top electrical connector 622 that mates to the retrieval subelectrical connector 313 shown in FIG. 9. These mating electricalconnectors 313 and 622 provide electrical energy from the wireline, andcommand and control signals, to and from the Smart Shuttle as necessaryto properly operate the Casing Saw. First casing saw blade 624 isattached to first casing saw arm 626. Second casing saw blade 628 isattached to second casing saw arm 630. Casing saw module 632 providesactuating means to deploy the arms, control signals, and the electricaland any hydraulic systems to rotate the casing saw blades. The casingsaw may have one or more downhole sensors to provide measuredinformation to the computer system on the surface. Further, this casingsaw may also possess one or more downhole sensors that providesinformation to the computer system that controls the well completionprocess. FIG. 16 shows the saw blades in their extended “out position”,but during any trip downhole, the blades would be in the retracted or“in position”. In part because the Casing Saw in FIG. 15 may be conveyeddownhole with the Retrieval Sub, it is an example of a “Smart CasingSaw”. Therefore, during this sixth step, the Casing Saw is suitablyattached to the Retrieval Sub, the Smart Shuttle Chamber 346 is suitablyprimed, and then the computer system 556 is operated using “Program C”that automatically controls the wireline drum and the Smart Shuttle sothat the Casing Saw is properly deployed at the correct depth, thecasing saw arms and saw blades are properly deployed, and the Casing Sawproperly cuts slots through the casing. The “internal pump of the SmartShuttle” 402 may be used in principle to make the Smart Shuttle go up ordown in the well, and in this case, as the saw cuts slots through thecasing, it moves up slowly under its own power—and under suitabletension applied to the wireline that is recommended to prevent adisastrous “overrun” of the wireline. After the slots are cut in thecasing, the Casing Saw is then returned to the surface of the earthunder “Program C” and thereafter, the communications system 564 sounds asuitable “alarm”, indicating that crew servicing is required—and in thiscase, the Casing Saw needs to be retrieved from the Smart ShuttleChamber. As an alternative, the previously described automated “hoppersystem” under control of the computer system can replace the functionsof the servicing crew therefore making this portion of the completion anentirely automated process, or as part of a closed-loop system tocomplete oil and gas wells. For a simple single-zone completion system,a coiled tubing conveyed packer can be used to complete the well. For asimple single-zone completion system, only several more steps arenecessary. Basically, the wireline system is removed and a coiled tubingrig is used to complete the well.

The seventh step is to close the first blow-out preventer 316 in FIG. 8.This will prevent any well pressure from causing problems in thefollowing procedure. Then, remove the Smart Shuttle and the RetrievalSub from the cablehead 304, and remove these devices from the SmartShuttle Chamber. Then, remove the bolts in flanges 376 and 368, and thenremove the entire Wireline Lubricator System 374 in FIG. 8. Then replacethe Wireline Lubricator System with a Coiled Tubing Lubricator Systemthat looks similar to element 374 in FIG. 8, except that the wireline inFIG. 8 is replaced with a coiled tubing. At this point, the CoiledTubing Lubricator System is bolted in place to flange 368 in FIG. 8.FIG. 17 shows the Coiled Tubing Lubricator System 634. The bottom flangeof the Coiled Tubing Lubricator System 636 is designed to mate to upperSmart Shuttle chamber flange 368. These two flanges join at the positionmarked by numeral 638. The Coiled Tubing Lubricator System in FIG. 17has various additional features, including a second blow-out preventer640, coiled tubing lubricator top body 642, fluid control pipe 644 andits fluid control valve 646, a hydraulic packing gland generallydesignated by numeral 648 in FIG. 17, having gland sealing apparatus650, grease packing pipe 652 and grease packing valve 654. In theindustry, the hydraulic packing gland generally designated by numeral648 in FIG. 17 is often called the “stripper” which has at least thefollowing functions: (a) it forms a dynamic seal around the coiledtubing when the tubing goes into the wellbore or comes out of thewellbore; and (b) it provides some means to change gland sealingapparatus or “packing elements” without removing the coiled tubing fromthe well. Coiled tubing 656 feeds through the Coiled Tubing LubricatorSystem and the bottom of the coiled tubing is at the position Y measuredfrom the position marked by numeral 638 in FIG. 17. Attached to thecoiled tubing a distance d1 above the bottom of the end of the coiltubing is the pump-down single zone packer apparatus 658. In severalpreferred embodiments of the invention, one or more downhole sensors,related electronics, related batteries or other power source, and one ormore communication systems within the pump-down single zone packerapparatus provide information to a computer system controlling the wellcompletion process. The entire system in FIG. 17 is then primed withfluids such as water using techniques already explained. Then, and withthe other appropriate valves closed in FIG. 17, primary injector tubevalve 344 is then opened, and water or other fluids are injected intoprimary injector tube 342. Then the pressure on top surface of thepump-down single zone packer apparatus forces the packer apparatusdownward, thereby increasing the distance Y, but when it does so, fluidΔV2 is displaced, and it goes up the interior of the coiled tubing andto coiled tubing pressure relief valve 660 near the coiled tubing rig(not shown in FIG. 17) and the fluid volume ΔV2 is emptied into aholding tank 662 (not shown in FIG. 17). Alternatively, instead ofemptying the fluid into the holding tank, the fluid can be suitablyrecirculated with a suitably connected recirculating pump, although thatrecirculating pump is not shown in FIG. 17 for brevity—and suchrecirculating pump would also minimize the size of the holding tankwhich is an important feature particularly for offshore use. Stillfurther, the pressure relief valve in the coiled tubing rig is not shownherein, nor is the holding tank, nor is the coiled tubing rig—solely forthe purposes of brevity. This hydraulic method of forcing, or “pulling”,the tubing into the wellbore will force it down into vertical sectionsof the wellbore. In such vertical sections of the wellbore, the weightof tubing also assists downward motion within the wellbore. However, ofparticular interest, this embodiment of the invention also worksexceptionally well to force, or “pull”, the coiled tubing intohorizontal or other highly deviated portions of the wellbore. This is asignificant improvement over other methods and apparatus typically usedin the industry. This embodiment of the invention can also be used incombination with standard mechanical “injectors” used in the industry.Those mechanical “injectors” provide an axial force on the coiled tubingforcing it into, or out of the well, and there are many commercialmanufactures of such devices. For example, please refer to the volumeentitled “Coiled Tubing and Its Applications”, having the author of Mr.Scott Quigley, presented during a “Short Course” at the “1999 SPE AnnualTechnical Conference and Exhibition”, October 3-6, Houston, Tex.,copyrighted by the Society of Petroleum Engineers, which society islocated in Richardson, Tex., an entire copy of which volume isincorporated herein by reference. With reference to FIG. 17, themechanical “injector” 663 (not shown in FIG. 17), the guide arch, thereel, the power pack, and the control cabin normally associated with anentire “coiled tubing rig” is not shown in FIG. 17 solely for thepurpose of brevity. If a mechanical “injector” is used to assist forcingthe pump-down single zone packer apparatus 658 into the wellbore, thenit is prudent to make sure that there is sufficient hydraulic forceapplied to the packer apparatus 658 so that the tubing along its entirelength is under suitable tension so that it will not “overrun” or“override” the packer apparatus 658. So, even if the mechanical“injector” is assisting the entry of the coiled tubing, the tubingshould still be “pulled down into the wellbore” by hydraulic pressureapplied to the pump-down single zone packer apparatus 658. FIG. 17Ashows additional detail in the pump-down single zone packer apparatus658 which possesses a wiper-plug type elastomeric main body having lobes659 that slide along the interior of the pipe, and in addition, aportion of the elastomeric unit is permanently attached to the tubing inthe region designated as 661 in FIG. 17A. The lobes 659 in theelastomeric unit are similar to the “Top Wiper Plug Lobe” 70 in FIG. 1.Hydraulic force applied to the elastomeric unit causes the tubing to be“pulled” into the pipe disposed in the wellbore, or “forced” into thepipe disposed in the wellbore, and therefore that elastomeric unit actslike a form of a “tractor” to pull that tubing into the pipe that isdisposed in wellbore. The pump-down single zone packer apparatus 658 inFIGS. 17 and 17A are very simple embodiments of the a “tubing conveyedsmart shuttles means” (also “tubing conveyed Smart Shuttle means”). Ingeneral, a “tubing conveyed smart shuttle means” also has “retrieval andinstallation means” for attachment of suitable “smart completion means”for yet additional embodiments of the invention that are not shownherein for brevity. For additional references on coiled tubing rigs, andrelated apparatus and methods, the interested reader is referred to thebook entitled “World Oil's Coiled Tubing Handbook”, M. E. Teel,Engineering Editor, Gulf Publishing Company, Houston, Tex., 1993, 126pages, an entire copy of which is incorporated herein by reference. Thecoiled tubing rig is controlled with the computer system 556 in FIG. 14and through the electronics interfacing system 572 and therefore thecoiled tubing rig and the coiled tubing is under computer control. Then,using techniques already described, the computer system 556 runs“Program D” that deploys the pump-down single zone packer apparatus 658at the appropriate depth from the surface of the earth. In the end, thiswell is completed in a configuration resembling a “Single-ZoneCompletion” as shown in detail in FIG. 18 on page 21 of the referenceentitled “Well Completion Methods”, Lesson 4, “Lessons in Well Servicingand Workover”, published by the Petroleum Extension Service, TheUniversity of Texas at Austin, Austin, Tex., 1971, total of 49 pages, anentire copy of which is incorporated herein by reference, and that waspreviously defined as “Ref. 2”. It should be noted that the coiledtubing described here can also have a wireline disposed within thecoiled tubing using typical techniques in the industry. From thisdisclosure in the seventh step, it should also be stated here that anyof the above defined smart completion devices could also be installedinto the wellbore with a tubing conveyed smart shuttle means or a tubingwith wireline conveyed smart shuttle means—should any other smartcompletion devices be necessary before the completion of the above step.It should be noted that all aspects of this seventh step including thecontrol of the coiled tubing rig, actuators for valves, any automatedhopper functions, etc., can be completely automated under the control ofthe computer system making this portion of the well completion anentirely automated process or as part of a closed-loop system tocomplete oil and gas wells.

The eighth step includes suitably closing first blow-out preventer 316or other valve as necessary, and removing in sequence the Coiled TubingLubricator System 634, the Smart Shuttle Chamber System 372, and theWiper Plug Pump-Down Stack 322, and then using usual techniques in theindustry, adding suitable wellhead equipment, and commencing oil and gasproduction. Such wellhead equipment is shown in FIG. 39 on page 37 ofthe book entitled “Testing and Completing”, Second Edition, Unit II,Lesson 5, published by the Petroleum Extension Service of the Universityof Texas, Austin, Tex., 1983, 56 pages total, an entire copy of which isincorporated herein by reference, that was previously defined as “Ref.4” above.

List of Smart Completion Devices

In light of the above disclosure, it should be evident that there aremany uses for the Smart Shuttle and its Retrieval Sub. One use was toretrieve from the drill string the Retrievable Instrumentation Package.Another was to deploy into the well suitable pump-down latching one-wayvalve means and a series of wiper plugs. And yet another was to deployinto the well and retrieve the Casing Saw.

The deployment into the wellbore of the well suitable pump-down latchingone-way valve means and a series of wiper plugs and the Casing Saw areexamples of “Smart Completion Devices” being deployed into the well withthe Smart Shuttle and its Retrieval Sub. Put another way, a “SmartCompletion Device” is any device capable of being deployed into the welland retrieved from the well with the Smart Shuttle and its Retrieval Suband such a device may also be called a “smart completion means”. These“Smart Completion Devices” may often have upper attachment apparatussimilar to that shown in elements 620 and 622 in FIG. 16.

Any “Smart Completion Device” may have installed within it one or moresuitable sensors, measurement apparatus associated with those sensors,batteries and/or power source, and communication means for transmittingthe measured information to the Smart Shuttle, and/or to a RetrievalSub, and/or to the surface. Any “Smart Completion Device” may also haveinstalled within it suitable means to receive commands from the SmartShuttle and or from the surface of the earth.

The following is a brief initial list of Smart Completion Devices thatmay be deployed into the well by the Smart Shuttle and its RetrievalSub:

-   -   (1) smart pump-down one-way cement valves of all types    -   (2) smart pump-down one-way cement valve with controlled casing        locking mechanism    -   (3) smart pump-down latching one-way cement valve    -   (4) smart wiper plug    -   (5) smart wiper plug with controlled casing locking mechanism    -   (6) smart latching wiper plug    -   (7) smart wiper plug system for One-Trip-Down-Drilling    -   (8) smart pump-down wiper plug for cement squeeze jobs with        controlled casing locking mechanism    -   (9) smart pump-down plug system for cement squeeze jobs    -   (10) smart pump-down wireline latching retriever    -   (11) smart receiver for smart pump-down wireline latching        retriever    -   (12) smart receivable latching electronics package providing any        type of MWD, LWD, and drill bit monitoring information    -   (13) smart pump-down and retrievable latching electronics        package providing MWD, LWD, and drill bit monitoring information    -   (14) smart pump-down whipstock with controlled casing locking        mechanism    -   (15) smart drill bit vibration damper    -   (16) smart drill collar    -   (17) smart pump-down robotic pig to machine slots in drill pipes        and casing to complete oil and gas wells    -   (18) smart pump-down robotic pig to chemically treat inside of        drill pipes and casings to complete oil and gas wells    -   (19) smart milling pig to fabricate or mill any required slots,        holes, or other patterns in drill pipes to complete oil and gas        wells    -   (20) smart liner hanger apparatus    -   (21) smart liner installation apparatus    -   (22) smart packer for One-Trip-Down-Drilling    -   (23) smart packer system for One-Trip-Down-Drilling    -   (24) smart drill stem tester

From the above list, the “smart completion means” includes smart one-wayvalve means; smart one-way valve means with controlled casing lockingmeans; smart one-way valve means with latching means; smart wiper plugmeans; smart wiper plug means with controlled casing locking means;smart wiper plugs with latching means; smart wiper plug means for cementsqueeze jobs having controlled casing locking means; smart retrievablelatching electronics means; smart whipstock means with controlled casinglocking means; smart drill bit vibration damping means; smart roboticpig means to machine slots in pipes; smart robotic pig means tochemically treat inside of pipes; smart robotic pig means to mill anyrequired slots or other patterns in pipes; smart liner installationmeans; and smart packer means.

In the above, the term “pump-down” may mean one or both of the followingdepending on the context: (a) “pump-down” can mean that the “internalpump of the Smart Shuttle” 402 is used to translate the Smart Shuttledownward into the well; or (b) force on fluids introduced by inlets intothe Smart Shuttle Chamber and other inlets can be used to force downwiper-plug like devices as described above. The term “casing lockingmechanism” has been used above that means, in this case, it locks intothe interior of the drill pipe, casing, or whatever pipe in which it isinstalled. Many of the preferred embodiments herein can also be used instandard casing installations which is a subject that will be describedbelow.

In summary, a “wireline conveyed smart shuttle means” has “retrieval andinstallation means” for attachment of suitable “smart completion means”.A “tubing conveyed smart shuttle means” also has “retrieval andinstallation means” for attachment of suitable “smart completion means”.If a wireline is inside the tubing, then a “tubing with wirelineconveyed shuttle means” (also “tubing with wireline conveyed SmartShuttle means”) has “retrieval and installation means” for attachment of“smart completion means”. As described in this paragraph, and dependingon the context, a “smart shuttle means” may refer to a “wirelineconveyed smart shuttle means” or to a “tubing conveyed smart shuttlemeans”, whichever may be appropriate from the particular usage. Itshould also be stated that a “smart shuttle means” may be deployed intoa well substantially under the control of a computer system which is anexample of a “closed-loop completion system”.

Put yet another way, the smart shuttle means may be deployed into a pipewith a wireline means, with a tubing means, with a tubing conveyedwireline means, and as a robotic means, meaning that the Smart Shuttleprovides its own power and is untethered from any wireline or tubing,and in such a case, it is called “an untethered robotic smart shuttlemeans” (also “an untethered robotic Smart Shuttle means”) for thepurposes herein.

It should also be stated for completeness here that any means that areinstalled in wellbores to complete oil and gas wells that are describedin Ref. 1, in Ref. 2, and Ref. 4 (defined above, and mentioned againbelow), and which can be suitably attached to the retrieval andinstallation means of a smart shuttle means shall be defined herein asyet another smart completion means. For example, in another embodiment,a retrieval sub may be suitably attached to a wireline-conveyed welltractor, and the wireline-conveyed well tractor may be used to conveydownhole various smart completion devices attached to the retrieval subfor deployment within the wellbore to complete oil and gas wells.

More Complex Completions of Oil and Gas Wells

Various different well completions typically used in the industry aredescribed in the following references:

-   -   (a) “Casing and Cementing”, Unit II, Lesson 4, Second Edition,        of the Rotary Drilling Series, Petroleum Extension Service, The        University of Texas at Austin, Austin, Tex., 1982 (defined        earlier as “Ref. 1” above)    -   (b) “Well Completion Methods”, Lesson 4, from the series        entitled “Lessons in Well Servicing and Workover”, Petroleum        Extension Service, The University of Texas at Austin, Austin,        Tex., 1971 (defined earlier as “Ref. 2” above)    -   (c) “Testing and Completing”, Unit II, Lesson 5, Second Edition,        of the Rotary Drilling Series, Petroleum Extension Service, The        University of Texas at Austin, Austin, Tex., 1983 (defined        earlier as “Ref. 4”)    -   (d) “Well Cleanout and Repair Methods”, Lesson 8, from the        series entitled “Lessons in Well Servicing and Workover”,        Petroleum Extension Service, The University of Texas at Austin,        Austin, Tex., 1971.

It is evident from the preferred embodiments above, and the descriptionof more complex well completions in (a), (b), (c), and (d) herein, thatSmart Shuttles with Retrieval Subs deploying and retrieving variousdifferent Smart Completion Devices can be used to complete a vastmajority of oil and gas wells. Here, the Smart Shuttles may be eitherwireline conveyed, or tubing conveyed, whichever is most convenient.Single string dual completion wells may be completed in analogy withFIG. 21 in “Ref. 4”. Single-string dual completion wells may becompleted in analogy with FIG. 22 in “Ref. 4”. A smart pig to fabricateholes or other patterns in drill pipes (item 19 above) can be used inconjunction with the a smart pump-down whipstock with controlled casinglocking mechanism (item 14 above) to allow kick-off wells to be drilledand completed.

It is further evident from the preferred embodiments above that SmartShuttles with Retrieval Subs deploying and retrieving various differentSmart Completion Devices can be also used to complete multilateralwellbores. Here, the Smart Shuttles may be either wireline conveyed, ortubing conveyed, whichever is most convenient. For a description of suchmultilateral wells, please refer to the volume entitled “MultilateralWell Technology”, having the author of “Baker Hughes, Inc.”, that waspresented in part by Mr. Randall Cade of Baker Oil Tools, that washanded-out during a “Short Course” at the “1999 SPE Annual TechnicalConference and Exhibition”, October 3-6, Houston, Tex., having thesymbol of “SPE International Education Services” on the front page ofthe volume, a symbol of the Society of Petroleum Engineers, whichsociety is located in Richardson, Texas, an entire copy of which volumeis incorporated herein by reference.

During more complex completion processes of wellbores, it may be usefulto alternate between wireline conveyed smart shuttle means and coiledtubing conveyed smart shuttle means. Of course, the “Wireline LubricatorSystem” 374 in FIG. 8 and the Coiled Tubing Lubricator System 634 inFIG. 17 can be alternatively mated in sequence to the upper SmartShuttle chamber flange 368 shown in FIGS. 8 and 17. However, if manysuch sequential operations, or “switches”, are necessary, then there isa more efficient alternative. One embodiment of this more efficientalternative is to suitably mount on top of the upper Smart Shuttlechamber flange 368, and at the same time, both a Wireline LubricatorSystem and a Coiled Tubing Lubricator System. There are many ways todesign and build such a system that allows for needed space forsimultaneously disposing wireline conveyed smart shuttle means andcoiled tubing conveyed smart shuttle means within the Smart ShuttleChamber 346, which chamber is generally shown in FIGS. 8 and 17, and inother pertinent portion of the system. Yet another embodiment comprisesat least one “motion means” and at least one “sealing means” so that theWireline Lubricator System and the Coiled Tubing Lubricator System canbe suitably moved back and forth with respect to the upper Smart Shuttlechamber flange 368, so that the unit that is required during any onestep is centered directly over whatever pipe is disposed in wellbore.There are many possibilities. For the purposes herein, a “DualLubricator Smart Shuttle System” is one that is suitably fitted withboth a Wireline Lubricator System and a Coiled Tubing Lubricator Systemso that either wireline or tubing conveyed Smart Shuttles can beefficiently used in any order to efficiently complete the oil and gaswell. Such a “Dual Lubricator Smart Shuttle System” would beparticularly useful in very complex well completions, such as in somemultilateral well completions, because it may be necessary to change theorder of the completion sequence if unforseen events transpire. Nodrawing is provided herein of the “Dual Lubricator Smart Shuttle System”for brevity, but one could easily be generated by suitable combinationof the relevant elements in FIGS. 8 and 17 and at least one “motionmeans” and at least one “sealing means”. Further, any “Dual LubricatorSmart Shuttle System” that is substantially under the control of acomputer system that also receives suitable downhole information isanother example of a closed-loop completion system to complete oil andgas wells.

Smart Shuttles and Standard Casing Strings

Many preferred embodiments of the invention above have referred todrilling and completing through the drill string. However, it is nowevident from the above embodiments and the descriptions thereof, thatmany of the above inventions can be equally useful to complete oil andgas wells with standard well casing. For a description of proceduresinvolving standard casing operations, see Steps 9, 10, 11, 12, 13, and14 of the specification under the subtitle entitled “Typical DrillingProcess”.

Therefore, any embodiment of the invention that pertains to a pipe thatis a drill string, also pertains to pipe that is a casing. Put anotherway, many of the above embodiments of the invention will function in anypipe of any material, any metallic pipe, any steel pipe, any drill pipe,any drill string, any casing, any casing string, any suitably sizedliner, any suitably sized tubing, or within any means to convey oil andgas to the surface for production, hereinafter defined as “pipe means”.

FIG. 18 shows such a “pipe means” disposed in the open hole 184 that isalso called the wellbore here. All the numerals through numeral 184 havebeen previously defined in relation to FIG. 6. A “pipe means” 664 isdeployed in the wellbore that may be a pipe made of any material, ametallic pipe, a steel pipe, a drill pipe, a drill string, a casing, acasing string, a liner, a liner string, tubing, or a tubing string, orany means to convey oil and gas to the surface for production. The “pipemeans” may, or may not have threaded joints in the event that the “pipemeans” is tubing, but if those threaded joints are present, they arelabeled with the numeral 666 in FIG. 18. The end of the wellbore 668 isshown. There is no drill bit attached to the last section 670 of the“pipe means”. In FIG. 18, if the “pipe means” is a drill pipe, or drillstring, then the retractable bit has been removed one way or another asexplained in the next section entitled “Smart Shuttles and RetrievableDrill Bits”. If the “pipe means” is a casing, or casing string, then thelast section of casing present might also have attached to it a casingshoe as explained earlier, but that device is not shown in FIG. 18 forsimplicity.

From the disclosure herein, it should now be evident that the abovedefined “smart shuttle means” having “retrieval and installation means”can be used to install within the “pipe means” any of the above defined“smart completion means”. Here, the “smart shuttle means” includes a“wireline conveyed shuttle means” and/or a “tubing conveyed shuttlemeans” and/or a “tubing with wireline conveyed shuttle means”.

Smart Shuttles and Retrievable Drill Bits

A first definition of the phrases “one pass drilling”,“One-Trip-Drilling” and “One-Trip-Down-Drilling” is quoted above to“mean the process that results in the last long piece of pipe put in thewellbore to which a drill bit is attached is left in place after totaldepth is reached, and is completed in place, and oil and gas isultimately produced from within the wellbore through that long piece ofpipe. Of course, other pipes, including risers, conductor pipes, surfacecasings, intermediate casings, etc., may be present, but the last verylong pipe attached to the drill bit that reaches the final depth is leftin place and the well is completed using this first definition. Thisprocess is directed at dramatically reducing the number of steps todrill and complete oil and gas wells.”

This concept, however, can be generalized one step further that isanother embodiment of the invention. As many prior patents show, it ispossible to drill a well with a “retrievable drill bit” that isotherwise also called a “retractable drill bit”. For example, see thefollowing U.S. Patents: U.S. Pat. No. 3,552,508, C. C. Brown, entitled“Apparatus for Rotary Drilling of Wells Using Casing as the Drill Pipe”,that issued on Jan. 5, 1971, an entire copy of which is incorporatedherein by reference; U.S. Pat. No. 3,603,411, H. D. Link, entitled“Retractable Drill Bits”, that issued on Sep. 7, 1971, an entire copy ofwhich is incorporated herein by reference; U.S. Pat. No. 4,651,837, W.G. Mayfield, entitled “Downhole Retrievable Drill Bit”, that issued onMar. 24, 1987, an entire copy of which is incorporated herein byreference; U.S. Pat. No. 4,962,822, J. H. Pascale, entitled “DownholeDrill Bit and Bit Coupling”, that issued on Oct. 16, 1990, an entirecopy of which is incorporated herein by reference; and U.S. Pat. No.5,197,553, R. E. Leturno, entitled “Drilling with Casing and RetrievableDrill Bit”, that issued on Mar. 30, 1993, an entire copy of which isincorporated herein by reference. Some experts in the industry call thistype of drilling technology to be “drilling with casing”. For thepurposes herein, the terms “retrievable drill bit”, “retrievable drillbit means”, “retractable drill bit” and “retractable drill bit means”may be used interchangeably.

For the purposes of logical explanation at this point, in the event thatany drill pipe is used to drill any extended reach lateral wellbore fromany offshore platform, and in addition that wellbore perhaps reaches 20miles laterally from the offshore platform, then to save time and money,the assembled pipe itself should be left in place and not tripped backto the platform. This is true whether or not the drill bit is left onthe end of the pipe, or whether or not the well was drilled withso-called “casing drilling” methods. For typical casing-while-drillingmethods, see the article entitled “Casing-while-drilling: The next stepchange in well construction”, World Oil, October, 1999, pages 34-40, andentire copy of which is incorporated herein by reference. Further, allterms and definitions in this particular article, and entire copies ofeach and every one of the 13 references cited at the end this articleare incorporated herein by reference.

Accordingly a more general second definition of the phrases “one passdrilling”, “One-Trip-Drilling” and “One-Trip-Down-Drilling” shallinclude the concept that once the drill pipe means reaches total depthand any maximum extended lateral reach, that the pipe means isthereafter left in place and the well is completed. The aboveembodiments have adequately discussed the cases of leaving the drill bitattached to the drill pipe and completing the oil and gas wells. In thecase of a retrievable bit, the bit itself can be left in place and thewell completed without retrieving the bit, but the above apparatus andmethods of operation using the Smart Shuttle, the Retrieval Sub, and thevarious Smart Production Devices can also be used in the drill pipemeans that is left in place following the removal of a retrievable bit.This also includes leaving ordinary casing in place following theremoval of a retrieval bit and any underreamer during casing drillingoperations. This process also includes leaving any type of pipe, tubing,casing, etc. in the wellbore following the removal of the retrievablebit.

In particular, following the removal of a retrievable drill bit duringwellboring activities, one of the first steps to complete the well is toprepare the bottom of the well for production using one-way valves,wiper plugs, cement, and gravel as described in relation to FIGS. 4, 5,and 8 and as further described in the “fifth step” above under thesubtopic of “Steps to Complete Well Shown in FIG. 6”. The use of one-wayvalves installed within a drill pipe means following the removal of aretrievable drill bit that allows proper cementation of the wellbore isanother embodiment of the invention. These one-way valves can beinstalled with the Smart Shuttle and its Retrieval Sub, or they can besimply pumped-down from the surface using techniques shown in FIG. 1 andin the previously described “fifth step”.

FIG. 18A shows a modified form of FIG. 18 wherein the last portion ofthe “pipe means” 672 has “pipe mounted latching means” 674. This “pipemounted latching means” may be used for a number of purposes includingat least the following: (a) an attachment means for attaching aretrievable drill bit to the last section of the “pipe means”; and (b) a“stop” for a pump-down one-way valve means following the retrieval ofthe retrievable drill bit. In some contexts this “pipe mounted latchingmeans” 674 is also called a “landing means” for brevity. Therefore, anembodiment of this invention is methods and apparatus to install one-waycement valve means in drill pipe means following the removal of aretrievable drill bit to produce oil and gas. It should also be statedthat well completion processes that include the removal of a retrievabledrill bit may be substantially under the control of a computer system,and in such a case, it is another example of automated completion systemor a part of a closed-loop completion system to complete oil and gaswells.

The above described “landing means” can be used for yet another purpose.This “landing means” can also be used during the one-trip-down-drillingand completion of wellbores in the following manner. First, a standardrotary drill bit is attached to the “landing means”. However, theattachment for the drill bit and the landing means are designed andconstructed so that a ball plug is pumped down from the surface torelease the rotary drill bit from the landing means. There are manyexamples of such release devices used in the industry, and no furtherdescription shall be provided herein in the interests of brevity. Forexample, relatively recent references to the use of a pumpdown plugs,ball plugs, and the like include the following: (a) U.S. Pat. No.5,833,002, that issued on Nov. 10, 1998, having the inventor of MichaelHolcombe, that is entitled “Remote Control Plug-Dropping Head”, anentire copy of which is incorporated herein by reference; and (b) U.S.Pat. No. 5,890,537 that issued on Apr. 6, 1999, having the inventors ofLavaure et. al., that is entitled “Wiper Plug Launching System forCementing Casing with Liners”, an entire copy of which is incorporatedherein by reference. After the release of the standard drill bit fromthe landing means, a retrievable drill bit and underreamer canthereafter be conveyed downhole from the surface through the drillstring (or the casing string, as the case may be) and suitably attachedto this landing means. Therefore, during the one-trip-down-drilling andcompletion of a wellbore, the following steps may be taken: (a) attach astandard rotary drill bit to the landing means having a releasingmechanism actuated by a releasing means, such as a pump down ball; (b)drill as far as possible with standard rotary drill bit attached tolanding means; (c) if the standard rotary drill bit becomes dull, drilla sidetrack hole perhaps 50 feet or so into formation; (d) pump down thereleasing means, such as a pump down ball, to release the standardrotary drill bit from the landing means and abandon the then dullstandard rotary drill bit in the sidetrack hole; (e) pull up on thedrill string or casing string as the case may be; (f) install a sharpretrievable drill bit and underreamer as desired by attaching them tothe landing means; and (f) resume drilling the borehole in the directiondesired. This method has the best of both worlds. On the one-hand, ifthe standard rotary drill bit remains sharp enough to reach final depth,that is the optimum outcome. On the other-hand, if the standard rotarydrill bit dulls prematurely, then using the above defined “SidetrackDrill Bit Replacement Procedure” in elements (a) through (f) allows forthe efficient installation of a sharp drill bit on the end of the drillstring or casing string, as the case may be. The landing means may alsobe made a part of a Smart Drilling and Completion Sub. If a RetrievableInstrumentation Package is present in the drilling apparatus, forexample within a Smart Drilling and Completion Sub, then the above stepsneed to be modified to suitably remove the Retrievable InstrumentationPackage before step (d) and then re-install the RetrievableInstrumentation Package before step (f). However, such changes are minorvariations on the preferred embodiments herein described.

To briefly review the above, many descriptions of closed-loop completionsystems have been described. One particular version of a closed-loopcompletion system uses a preferred embodiment that discloses methods ofcausing movement of shuttle means having lateral sealing means within a“pipe means” disposed within a wellbore that includes at least the stepof pumping a volume of fluid from a first side of the shuttle meanswithin the pipe means to a second side of the shuttle means within thepipe means, where the shuttle means has an internal pump means. Pumpingfluid from one side to the other of the smart shuttle means causes it tomove “downward” into the pipe means, or “upward” out of the pipe means,depending on the direction of the fluid being pumped. The pumping ofthis fluid causes the smart shuttle means to move, translate, changeplace, change position, advance into the pipe means, or come out of thepipe means, as the case may be, and may be used in other types of pipes.The “pipe means” deployed in the wellbore may be a pipe made of anymaterial, and may be a metallic pipe, a steel pipe, a drill pipe, adrill string, a casing, a casing string, a liner, a liner string,tubing, a tubing string, or any means to convey oil and gas to thesurface for oil and gas production. There are many embodiments of SmartShuttles, but the particular embodiment of a Smart Shuttle described inthe foregoing is particularly useful for operation within any pipe meansand for closed-loop completion systems.

Smart Shuttle with Progressive Cavity Pump

As stated earlier, several embodiments of the Smart Shuttle use apositive displacement pump. There is a particularly useful version of apositive displacement pump called a Progressive Cavity Pump (“PCP”). Inturn, that PCP is coupled to a gear box that is in turn driven by anElectrical Submersible Motor (“ESM”). Such a configuration is called a“PCP/ESM” for short. Sometimes, the overall assembly is simply called anElectrical Submersible Pump (“ESP”).

FIG. 19 shows a PCP/ESM Smart Shuttle generally designated with thenumeral 676 that is located within a “pipe means” 678 that includes acasing, drill pipe, tubing, etc. The PCP/ESM Smart Shuttle is comprisedof a Progressive Cavity Pump 680 of the type typically used in the oiland gas industries such as that manufactured by Tarby Inc., 2205 E. L.Anderson Boulevard, Clarmore, Okla. 74017, that is further described inthat firm's catalogue entitled “Progressing Cavity Solutions thruService, Parts and Pumps”. That Progressive Cavity Pump has a rotor 681and stator 682 as is typical of such pumps. The Progressive Cavity Pumpis coupled to gear box 683 that is in turn coupled to the ElectricallySubmersible Motor 684, which in turn is connected to electronicsassembly 685 having any downhole computer, the downhole sensors, andcommunications system, which in turn is connected by the quick changecollar 686 to the cablehead 688 that is suspended by the wireline 690.The lower wiper plug assembly 692 has sealing lobe 694 and this assemblyis firmly attached to the body of the Progressive Cavity Pump at thelocation generally specified by numeral 696 and this assembly furtherhas lower bypass passage 698 which has electrically operated valves 700and 702. The upper wiper plug assembly 704 has sealing lobe 706 and thisassembly is firmly attached to the sections of the apparatus having thegear box and the Electrically Submersible Motor at the locationgenerally designated by numeral 708. The upper wiper assembly also haspermanently open upper bypass port 710 in the embodiment shown in FIG.19.

In terms of FIG. 19, and when the Electrically Submersible Motor issuitably turning the rotor of the Progressive Cavity Pump (PCP), avolume of fluid ΔV2 in the wellbore is pumped into the lower side port712 of the PCP and out of the upper side port 714 of the PCP. Withvalves 700 and 702 closed, the fluid ΔV2 is then forced through theupper bypass port 710 into the portion of the well above the uppersurface of the upper wiper plug assembly that is identified by numeral716. In this manner, the Smart Shuttle is then forced downward into thewellbore.

In analogy with previous embodiments, the Retrieval Sub 718 is attachedto the body of the Smart Shuttle by quick change collar 720 that in turnis connected to the lower body of the Progressive Cavity Pump. The SmartShuttle and its Retrieval Sub otherwise operate in manners and forpurposes previously described herein. The point is that this embodimentof the invention is particularly relevant to operation within any pipemeans which may be a casing, a drill pipe, etc. The electrical wiringfrom the cablehead and the electronics assembly 685 that passes throughthe PCP to the Retrieval Sub is not shown in FIG. 19 for the purposes ofsimplicity only.

In FIG. 19, the lobe 706 of the upper wiper plug assembly 704 must sealagainst the inside of the pipe means for proper operation of the SmartShuttle. To that end, various different embodiments of the inventionprovide for different adjustable sealing means to compensate forvariations in the ID of the pipe means present.

The PCT/ESM Smart Shuttle shown as element 676 in FIG. 19 is an exampleof “a conveyance means”.

FIG. 20 shows one embodiment of the invention that has an adjustablesealing means generally designated by the numeral 722 in FIG. 20. Inthis case, the adjustable sealing means, or adjustable sealing apparatus722, is comprised of a hydraulic port 724 from inside of the adjacenttool body 725 that provides hydraulic oil under pressure which inflatesinflatable gland 726. With a first hydraulic pressure “P1” on the fluidwithin the inflatable gland, the solid lines show the outline of theadjustable sealing apparatus. With a second hydraulic pressure “P2” onthe fluid within the inflatable gland, the dotted lines show the outlineof the adjustable sealing apparatus. With hydraulic pressure “P2”, thelobe 728 of the adjustable sealing apparatus makes suitable contact withthe interior of the pipe means 730. A bypass port 732 is shown in FIG.20 which also shows the relaxed state under pressure P1 (solid line) andthe energized state under pressure P2 (dotted line).

Closed-Loop System to Complete Cased Wells with Smart Shuttles

Any type of Smart Shuttle with Retrieval Sub may be used to completecased wells. However, the above PCP/ESM Smart Shuttle is particularlyattractive. This PCP/ESM Smart Shuttle may be wireline conveyed as shownin FIG. 19, or may be “tubing conveyed”, or may be “tubing with wirelineconveyed” as desired. The PCP/ESM Smart Shuttle is particularly usefulfor the close-loop completion of oil and gas wells. Several embodimentsof the invention involving the closed-loop completion of oil and gaswells follow in FIGS. 21 and 22.

As a brief review, FIGS. 18 and 18A showed a casing being disposed inthe wellbore. FIGS. 19 and 20 showed a particular type of Smart Shuttlethat can be used to complete any “pipe means” disposed in a wellbore,where this “pipe means” specifically includes a casing string. FIG. 21shows a casing string in the process of being completed with a SmartShuttle and other devices disposed in the casing string.

All the numerals in FIG. 21 through numeral 666 have been previouslydefined heretofore in the specification. In FIG. 21, the final length ofcasing 734 possesses “pipe mounted latching means” 736 that is alsocalled a “landing means”. This “landing means” was previously describedin relation to FIG. 18A, and in its simplest form, it provides at leasta mechanical stop for various devices. Wiper plug 738 with one-way valvemeans 740 had been pumped down from the surface and it wiped drillingmud off the interior of the casing and it came to rest against the“landing means”. Then, perforable wiper plug 742 pumped down a charge ofcement 744 shown in FIG. 21. Then, perforable wiper plug 746 pumped downa charge of gravel 748. Then, solid wiper plug 750 pumped down the finalcharge of cement 752. As further shown in FIG. 21, a Smart Shuttle 754having a Retrieval Sub 756 is attached to a Casing Saw 758 that in turnsaws slots in the casing as previously described. The cable head 760 isattached to the Smart Shuttle as previously described, and in turn, itis attached to the wireline 762. The operations shown in FIG. 21 may beexecuted substantially under the control of a computer system which isanother example of a “closed-loop completion system”. One embodiment ofsuch a computer system is shown in FIG. 14. It should also be noted thatif the above wiper plugs are deployed into the wellbore by initialattachment to the Retrieval Sub, then these wiper plugs can also bedescribed as “smart wiper plugs”.

The Smart Shuttle shown as element 754 in FIG. 21 is an example of “aconveyance means”.

FIG. 22 shows a section view of the pump-down single zone packerapparatus installed in the casing string. The slots 764 made by theCasing Saw are evident in the casing string. The pump-down single zonepacker apparatus 766 is shown in FIG. 22 and it had been previouslydescribed in relation to element 658 in FIG. 17. As is the case in FIG.17, in several preferred embodiments of the invention, one or moredownhole sensors, related electronics, batteries or other power source,and one or more communication systems within the pump-down single zonepacker apparatus 766 provide information to a computer systemcontrolling the well completion process. The pump-down single zonepacker apparatus 766 is attached to coiled tubing 768 as previouslydescribed in relation to FIG. 17. Again, the operations shown in FIG. 22may be executed substantially under the control of a computer systemwhich is another example of a “closed-loop completion system”. Again,one embodiment of such a computer system is shown in FIG. 14. FIG. 14provides for the computer operation of a coiled tubing rig because ofthe following quote from the text that describes FIG. 14: “Electronicsinterfacing system 572 also provides power and electronic control of anycoiled tubing rig designated by element 591 (not shown in FIG. 14),including the coiled tubing drum hydraulic motor and pump assembly ofthat coiled tubing rig, but such a coiled tubing rig is not shown inFIG. 14 for the purposes of simplicity.”

Definitions of Closed-Loop Systems and Automated Systems to Complete Oiland Gas Wells

The Glossary of Ref. 4 described earlier defines the term “to complete awell” to be the following: “to finish work on a well and bring it toproductive status. See well completion.” The term “to complete a well”may also be used interchangeably with the term “to complete a wellbore”.

The Glossary of Ref. 4 further defines term “well completion” to be thefollowing: “1. the activities and methods of preparing a well for theproduction of oil and gas; the method by which one or more flow pathsfor hydrocarbons is established between the reservoir and the surface.2. the systems of tubulars, packers, and other tools installed beneaththe wellhead in the production casing, that is, the tool assembly thatprovides the hydrocarbon flow path or paths.” To be precise for thepurposes herein, the term “completing a well” or the term “completingthe well” are each separately equivalent to performing all the necessarysteps for a “well completion”.

For the purposes herein, in several preferred embodiments of theinvention, the term “well completion system” shall mean apparatus andrequired procedures that are used “to complete a well” and which arecapable of providing the equipment and methods of operation necessaryfor “well completion”.

For the purposes herein, in several preferred embodiments of theinvention, the term “automated well completion system”, or “automatedsystem for well completion”, or “automated system to complete an oil andgas well” shall mean the following: a well completion system having atleast one downhole component located in the well that may also have oneor more uphole components located in the vicinity of a drilling rigwhich are controlled by a computer executing programmed steps during atleast “one significant portion of the well completion process”—a termdefined below. Here, “uphole” may be on the ocean bottom near thepresent location of the drilling rig or near the location were thedrilling rig was previously positioned during the drilling of the well.

For the purposes herein, in several embodiments of the invention, theword “automated” as it refers to any process in many embodiments of theinvention shall mean that the process is simply under computer control.

For the purposes herein, and for several preferred embodiments of theinvention, the term “closed-loop system for well completions”, or “aclosed-loop system to complete wellbores”, or “a closed-loop system tocomplete oil and gas wells”, shall mean the following: an automated wellcompletion system having at least a downhole component and/or one ormore uphole components controlled by a computer, that has at least onedownhole sensor and at least one uphole sensor that provide informationto the computer, whereby the execution of the programmed steps by thecomputer to control the components takes into account the informationfrom the uphole and the downhole sensors to optimize and/or change thesteps executed by the computer to complete the well. Here, “uphole” maybe on the ocean bottom near the present location of the drilling rig ornear the location were the drilling rig was previously positioned duringthe drilling of the well. Further, the downhole component may alsoinclude the downhole sensor. Yet further, any uphole component may alsoinclude any uphole sensor.

For the purposes herein, in several preferred embodiments of theinvention, the phrase “closed-loop” as it refers to any process in manyembodiments of the invention shall mean that the process is not onlyunder computer control, but in addition, this process uses at least somedownhole information that is communicated to the surface to optimizeand/or change the steps executed by the computer to complete the well.

As an example of the above, the title of an invention for many preferredembodiments herein described could have read as follows: “CLOSED-LOOPAUTOMATED SYSTEM TO COMPLETE OIL AND GAS WELLS”. However, from the abovedefinitions, the term “closed-loop” implies that an automated system isexecuting steps that depend in part on information communicated from atleast one downhole sensor to the surface. Therefore, for certainpreferred embodiments, the word “automated” following “closed-loop”would be redundant.

As another example of the above, the title of an invention for manypreferred embodiments herein described could also have read as follows:“AUTOMATED SYSTEM TO COMPLETE OIL AND GAS WELLS”. However, using theexact phrases as defined herein, this might not necessarily include all“closed-loop” systems having at least one downhole sensor.

For the purposes herein, in several preferred embodiments of theinvention, the term “one significant portion of the well completionprocess”, shall be defined as the series of steps executed by thecomputer that sends a device attached to a wireline or coiled tubinginto any depth in the well and returns the wireline or coiled tubing tothe surface—whether or not the device is installed in the well or isattached to the wireline or coiled tubing. The definition of the term“one significant portion of the well completion process” also includesthe step of sending a device attached to a wireline or coiled tubinginto the well during “one trip”, meaning “one trip down” into the welland “one trip back” to the surface. Here, the term “one trip” does notnecessarily imply any time duration, and this step may be done in anhour, a day, or many years in the case of semi-permanently installedinstrumentation for reservoir monitoring purposes that are installedduring the well completion process. It should also be stated for claritythat the term “well completion process” in some preferred embodimentsalso includes the steps of installing into the wellbore devices tomonitor production for long periods of time.

Following the above described steps of installing into the wellboredevices to monitor production, several preferred embodiments alsoprovide steps for installing into the wellbore devices to adjust,change, or control the production of oil and gas from within the wells.In several embodiments, the step to monitor production and the step tocontrol production may be executed during the sequence of steps that arenecessary to complete the oil and gas well. Alternatively, and inseveral embodiments, the step to monitor production and the step tocontrol production may be executed following the sequence of steps thatare necessary to complete the oil and gas well. For the sake of brevity,several alternative sequence of events evident from the above disclosurewill not be further discussed here. Therefore, production monitoringmeans to monitor production may be installed during, or after the wellcompletion process. Therefore, production controlling means may beinstalled during, or after the completing the well. It should also berealized that the means to monitor production may include means tomonitor the total hydrocarbon production, and/or to separately monitorthe oil and/or gas and or/water production. Further, the means tocontrol production may include means to control the total production ofhydrocarbons, and/or to separately control the production of the oiland/or gas and/or water from the wellbore.

To further elaborate on the previous paragraph, various preferredembodiments include at least one sensor remaining in the wellbore asmeans to monitor the production of hydrocarbons from the wellbore aftercompleting the wellbore. Other preferred embodiments include means tocontrol the production of hydrocarbons that are disposed into thewellbore and remain installed in the wellbore after completing thewellbore. And further, in yet other preferred embodiments, the means tomonitor the production of hydrocarbons from the wellbore may also beused to adjust the means to control the production of hydrocarbons fromthe wellbore following the completion of the wellbore, which lattermeans may be defined herein as an “adjustable means to control theproduction of hydrocarbons” from within the wellbore. Yet further, otherembodiments provide for the “remote actuation of the adjustable means tocontrol the production of hydrocarbons”, a term defined herein. Theremote actuation includes remote actuation from the surface of theearth, from an offshore drilling platform, or from any device installedwithin the wellbore, such as from the means to monitor the production ofhydrocarbons within the wellbore. In yet further embodiments of theinvention, a closed-loop system to complete a well for producinghydrocarbons from the earth may also be used for the second purpose as aclosed-loop system to monitor, control, and maintain production from thewell.

For the purposes herein, in several preferred embodiments of theinvention, the phrase “computer system”, and/or the word “computer”,and/or the phrase “computer means”, shall mean: one or more electronicmachines which by means of stored instructions and information, performsrapid, calculations and/or compiles, correlates, and selects dataincluding remote sensory data, that is used to control the wellcompletion process and related processes through a series of stepsexecuted by the machine or machines, each of which may have a data bus,a processor, a nonvolatile memory, a read only memory, an analogue todigital converter, a controller, electronic systems, and any other meansnecessary to control an automated well completion system. It should beexplicitly stated that the steps actually executed by the computersystem may change or be altered as a result of data provided by one ormore remote sensors. The term “computer system”, or the word “computer”,shall also explicitly include one or more “distributed computers” linkedtogether by suitable data communications systems, or “communicationsmeans”. For example, and for the purposes herein, the term “computersystem”, or the word “computer”, shall mean the combination of any orall computers at the wellsite, and any or all remotely locatedcomputers, such as computers onshore during offshore drilling andcompletion operations, and all of their associated communications links,and other related computation means and data banks, which togethercomprise a “distributed computer system” or simply as a “computer systemmeans”. Accordingly, and under various circumstances, the phrases“computer system”, “computer”, “computer means”, “distributed computersystem”, and “computer system means” may be used equivalently as thecase may be.

For the purposes herein, in many preferred embodiments, the term“wireline” shall mean a flexible, armor encapsulated, collection ofinsulated wires that may include one or more optical cables, and wherethe collection of insulated wires often includes 7 conductors, but whichmay in principle mean any number of such conductors capable of carryingany amount of current, providing any voltage levels required, andproviding any net required power that is to be delivered downhole. Suchwirelines are routinely used in the oil and gas industries for logging,production, and for other proposes.

Using the above definitions, it should also be noted that anotherembodiment of a closed-loop system to complete oil and gas wells iscomprised of a Retrieval Sub that is suitably attached to awireline-conveyed well tractor. In this embodiment, thewireline-conveyed well tractor is used to convey downhole various SmartCompletion Devices attached to the Retrieval Sub for deployment withinthe wellbore to complete oil and gas wells. In one embodiment, the SmartCompletion Device attached to the Retrieval Sub during conveyancedownhole provides information to the computer system, and thisinformation affects the series of steps leading to the completion of theoil and gas well. Therefore, one embodiment is a wireline-conveyed welltractor automated under the control of a computer system that alsopossesses means to convey uphole various sensory data that affects theseries of steps to complete the well. Consequently, this embodiment isalso yet another example of a closed-loop system to complete oil and gaswells.

It is also to be noted that in preferred embodiments of the invention,the well is initially completed using a closed-loop system.Consequently, this initially completed well is “completed a first time”,a term defined herein. If there are problems with the initialproduction, or if there are ongoing production problems, the well may be“completed a second time”, a term defined herein. As is often the casewith aging reservoirs, initially satisfactory hydrocarbon producingintervals may begin to produce progressively unacceptably large amountsof water in time. Accordingly, it may be required to complete the well asecond time, or using other words, it may be necessary to “recompletethe well”, a term defined herein. The term “to recomplete the well” mayalso refer to any successive third, fourth, fifth, etc. completion of agiven well. Therefore, after completing a well a first time, the wellmay be recompleted, thereby completing the well a second time tooptimize the production of hydrocarbons from the earth.

Closed-Loop Systems and Automated Systems in Relation to FIGS. 21 and 22

In relation to FIG. 21, the Smart Shuttle, the Retrieval Sub, and anyone of the Smart Completion Devices including the smart wiper plugs, mayhave one or more downhole sensors, related electronics, batteries orother power source, and one or more communications systems to providemeasured information to the computer system controlling the wellcompletion process.

In relation to FIG. 22, and in several preferred embodiments of theinvention, one or more downhole sensors, related electronics, batteriesor other power source, and one or more communication systems within thepump-down single zone packer apparatus 766 provide information to thecomputer system controlling the well completion process.

Therefore, in relation to FIGS. 21 and 22, many different devices may beconveyed into the well having sensors that provide information to acomputer system. An example of such a computer system is element 556 inFIG. 14. Various embodiments describe the computer system in FIG. 14controlling the steps to complete the oil and gas well as shown in FIGS.21 and 22.

Put differently, in various embodiments shown in FIGS. 21 and 22, thecomputer system 556 is used to control the well completion process. Thesteps in this well completion process depend in part upon informationprovided from the downhole sensors described in relation to FIGS. 21 and22.

Accordingly, it is now evident that the disclosure related to FIGS. 21and 22 describe an automated well completion system for producinghydrocarbons from a wellbore in the earth that is substantially underthe control of a computer system that executes a sequence of programmedsteps.

Further, disclosure related to FIGS. 21 and 22 describe a closed-loopsystem to complete a well for producing hydrocarbons from the earth.

Yet further, disclosure related to FIGS. 21 and 22 provide a method ofcompleting a wellbore to produce hydrocarbons from the earth that issubstantially under the control of an automated computer system thatexecutes a sequence of programmed steps.

And finally, disclosure related to FIGS. 21 and 22 provide a method tocomplete a wellbore to produce hydrocarbons from the earth that issubstantially under the control of a closed-loop automated system thatexecutes a sequence of programmed steps, whereby the steps depend uponinformation obtained from at least one sensor located within thewellbore, and whereby the steps are executed during one significantportion of the well completion process.

In relation to FIGS. 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 17, 17A, 18, 18A,19, 20, 21, and 22, it is evident that after completing the wellbore,the wellbore is comprised of at least a borehole in a geologicalformation that surrounds a pipe located within the borehole, and thispipe may be any one of the following: a metallic pipe; a casing string;a casing string with any retrievable drill bit removed from thewellbore; a steel pipe; a drill string; a drill string possessing adrill bit that remains attached to the end of the drill string aftercompleting the wellbore; a drill string with any retrievable drill bitremoved from the wellbore; a coiled tubing; a coiled tubing possessing amud-motor drilling apparatus that remains attached to the coiled tubingafter completing the wellbore; or a liner.

Smart Shuttle Assisted Coiled Tubing Deployment

As a brief review, FIG. 22 shows a section view of the pump-down singlezone packer apparatus installed in the casing string. In this simpleapplication of coiled tubing technology, the pump-down single zonepacker apparatus 766 was pumped down with pressure from the surface andwith the assistance of force added by the mechanical “injectors” thatwere described in relation to FIG. 17.

However, the Smart Shuttles may be conveyed downhole with coiled tubing.Such a Smart Shuttle with Retrieval Sub that is conveyed downhole bycoiled tubing is shown in FIG. 23. In fact, the coiled tubing conveyedSmart Shuttle in FIG. 23 is forced downhole by three differentmechanisms: (a) mechanical “injectors” at the surface force the coiledtubing downward at the wellhead; (b) the PCP/ESM assembly may be used toassist by “pulling” the Smart Shuttle into the wellbore; and (c) yetfurther, hydraulic forces from the surface also force the Smart Shuttleinto the wellbore. That these three independent methods may be used toforce the Smart Shuttle with its attached Retrieval Sub downward intothe wellbore will become better apparent with the following descriptionof the elements in FIG. 23.

All the elements in FIG. 23 through element 720 have been previouslydescribed. The Progressive Cavity Pump is labeled with element 680. TheProgressive Cavity Pump is coupled to gear box 683 that is in turncoupled to the Electrically Submersible Motor 684, which in turn isconnected electronics assembly 685 having any downhole computer,sensors, and communications system, which in turn is connected to thequick change collar 770. The assembly below the quick change collar inFIG. 23 is often referred to as the Progressive Cavity Pump/ElectricalSubmersible Motor assembly that is abbreviated as the “PCP/ESMassembly”. Therefore, the “PCP/ESM assembly” is attached to the quickchange collar 770 in FIG. 23.

Coiled tubing 772 has wireline 774 installed within it. Coiled tubing772 also has threaded end 776. Tubing Termination Assembly 778 hasthreads 780 that mate to the threaded end 776 of the coiled tubing. So,the Tubing Termination Assembly is suspended within the casing from thethreaded end 776 of the coiled tubing. Any fluids that flow into, or outof, the coiled tubing are conducted to and from the interior of thecasing through fluid channel 782. Valve 783 located within fluid channel782 can be used to positively shut off fluid flow through the channel,but valve 783 is not shown in FIG. 23 solely for the purposes ofsimplicity. For many of he following embodiments, it is assumed thatthis valve 783 is open unless explicitly stated otherwise. The wireline774 is connected to top submersible plug 784 that connects to lowersubmersible plug 786 which in turn passes the electrical conductors fromthe wireline to the quick change collar. The bundle of electricalconductors passing to the quick changer collar is designated with thenumeral 788 in FIG. 23. Within the quick change collar is yet anotherelectrical plug assembly that provides power and electrical signalsthrough a bundle of wires to the “PCP/ESM assembly” that is not shown inFIG. 23 solely for the purposes of simplicity. Typical design andassembly procedures used in the industry are assumed throughout thisapplication. It is often the case that a quick change collar surroundsmale and female mating electrical connectors, which is typically thecase in “logging tools” used in the wireline logging industry. Thoseconnectors mate at the location specified by the dashed line 789 shownon the interior of the quick change collar in FIG. 23.

In addition, the Tubing Termination Assembly 778 also possessesexpandable packer 790. Upon command from the surface, this expandablepacker can be inflated within the casing to seal against the casing asmay be required during typical well completion procedures, and typicalworkover procedures, that are used in the industry. This expandablepacker can also be used for a second purpose of forcing the SmartShuttle into the wellbore as described below.

With reference to FIG. 23, the Smart Shuttle may be forced downhole bythree mechanisms that are described in separate paragraphs as follows.

First, mechanical “injectors” at the surface force the coiled tubingdownward at the wellhead. These mechanical “injectors” have beenpreviously described.

Second, the electrically energized Progressive Cavity Pump forces fluidΔV2 into the lower side port 712 of the PCP and out of the upper sideport 714 of the PCP, and the Smart Shuttle is conveyed downhole. If thismethod is used by itself, then no fluid would necessarily flow to thesurface through fluid channel 782. It could, but it is not necessary inthis embodiment, and under the circumstances described.

Third, and in analogy with the pump-down single zone packer apparatus658 described in FIG. 17, the expandable packer 790 in FIG. 23 isinflated so as to make a reasonable seal against the casing, but not sofirmly so as to lock the device in place. In FIG. 23, the solid linelabeled with numeral 790 shows the uninflated state of the expandablepacker, and the dotted line shows the expanded state of expandablepacker 790. Then, in analogy with fluid flow described in FIG. 17, fluidforced into the upper wellbore will force the apparatus attached to theexpandable packer downward into the wellbore, and any fluid ΔV3displaced is forced upward through fluid channel 782 and into theinterior of the coiled tubing which in turn flows to the surface inanalogy with previous description of fluid flow through coiled tubing tothe surface in relation to FIG. 17.

In principle, all first, second, and third methods of conveyancedownhole can be used simultaneously, provided that valves 698 and 700are closed, and provided the Progressive Cavity Pump 680 is suitablyenergized.

For simplicity, the particular embodiment of the invention shown in FIG.23 will be called in certain portions of the text that follows a “coiledtubing with wireline Smart Shuttle” abbreviated “CTWWSS”, that isgenerally designated as numeral 792 in FIG. 23.

Any smart completion device may be attached to the Retrieval Sub 718during any such conveyance downhole. For example, a casing saw oranother packer can be installed on the Retrieval Sub so that manydifferent services can be performed during one trip downhole. Theseinclude perforating, squeeze cementing, etc.—in fact many of the methodsto complete oil and gas wells defined in the book entitled “WellCompletion Methods”, “Well Servicing and Workover”, Lesson 4, from theseries entitled “Lessons in Well Servicing and Workover”, PetroleumExtension Service, The University of Texas at Austin, Austin, Tex., 1971(previously defined as “Ref. 2” above), an entire copy of which isincorporated herein by reference.

The apparatus in FIG. 23 may be used to test production or to assistproduction if it is used in another manner. In this embodiment, anelectrically actuated casing lock 794 (not shown in FIG. 23) is attachedto the Retrieval Sub 718. It has passages through it so thathydrocarbons below it can pass through it if necessary, but it otherwiselocks the apparatus in FIG. 23 to the inside of the casing. Once lockedin place, the PCP/ESM assembly can pump hydrocarbons through lower sideport 712 of the PCP and out of the upper side port 714 of the PCP.Thereafter, hydrocarbons are pumped through fluid channel 782 of theTubing Termination Assembly 778 in FIG. 23 provided that the expandablepacker 790 is suitably inflated. There are many variations on thisembodiment of the invention but they are not further described heresolely in the interests of brevity.

The “coiled tubing with wireline Smart Shuttle” abbreviated “CTWWSS” asgenerally designated as numeral 792 in FIG. 23 is an example of “aconveyance means”.

Universal Smart Completion Devices for Closed-Loop Systems to CompleteOil and Gas Wells

FIG. 24 shows a Universal Smart Completion Device (USCD) that isgenerally designated by the element 796. The USCD in FIG. 24 is used inseveral preferred embodiments of closed-loop systems to complete oil andgas wells. The USCD is disposed within “pipe means” 798 that includes acasing, drill pipe, tubing, a metallic pipe of any type, any type ofpipe, etc. Upper attachment apparatus 800 of the USCD provides similarapparatus and mechanical functions as provided by element 620 in FIG.16, and by element 206 of the Retrieval Instrumentation Package in FIG.7. The USCD also has top electrical connector 802 that mates to theretrieval sub electrical connector 313 shown in FIG. 9 and to connector313 shown in FIG. 23. The body 804 of the USCD has first recession 806and second recession 808. First controlled casing locking mechanism 810is conveyed downhole with its arm retracted within the first recession.Upon a suitable command, it is locked into place against the inside ofthe casing or pipe. Second controlled casing locking mechanism 812 isconveyed downhole with its arm retracted within the second recession.Upon a suitable command, it is also locked into place against the insideof the casing or pipe. Internal bore 814 within the USCD allows fluidsto flow through the interior of the USCD under certain circumstances.Lower valve 816 of the USCD may be opened or closed on command. Uppervalve 818 of the USCD may be opened or closed on command.

The USCD in FIG. 24 also possesses expandable packer 820. Upon commandfrom the surface, this expandable packer can be inflated within thecasing (or pipe) to seal against the casing as may be required duringtypical well completion procedures and typical workover procedures thatare used in the industry. The solid line shows the expandable packer ina position where fluids can flow by it between the USCD and the pipewall. The dashed line shows the expandable packer in a position wherefluids cannot flow by it between the USCD and the pipe wall.

First internal fluid flow control valve 822 is used to control the flowof fluids through the internal bore 814 within the USCD. Second internalfluid flow control valve 824 is also used to control the flow of fluidsthrough the internal bore 814 within the USCD. The pressure in thefluids flowing through the internal bore of the USCD is measured withpressure gauge 826 in FIG. 24. Ancillary measurement package 828measures the temperature, and provides any other desirable physicalmeasurements such as measurements of the “basic flow rate, or thedetailed measurements of the relative amounts of water, oil and gasflowing by this measurement package. Ancillary measurement package 828provides any downhole sensors, or sensor means, and any downholemonitors, or monitoring means.

In FIG. 24, USCD electronics package 830 provides all necessaryelectronics to operate the upper and lower valves, to operate the firstand second controlled casing locking mechanisms, to operate the firstand second internal fluid flow control valves, to accept communicatedcommands from the surface and/or from the Smart Shuttle and itsRetrieval Sub, to provide all desired downhole sensors, to providemeasurements from the downhole sensors, and to provide communications tothe surface and/or the Smart Shuttle and its Retrieval Sub. Virtuallyany electronic, sensor, or sensor measurement function previouslydescribed with regards to a Smart Shuttle, a Retrieval Sub, a SmartCompletion Device, and/or a Retrievable Instrumentation Package may beincorporated into the USCD as different embodiments of the inventionherein.

Electronics package 830 also possesses suitable power sources to provideany required power to the USCD such as batteries and/or batteries thatmay be recharged through the wireline if the USCD is connected to theRetrieval Sub of a Smart Shuttle. Such rechargeable batteries may berecharged downhole or uphole as desired by the operator. It may bedesirable to have additional features incorporated into the USCD fordifferent classes of well completions. However, such additionalelectronics and other features would be conveniently added to the USCDin a modular fashion so that in this preferred embodiment, nosubstantial changes would be required to the mechanical apparatus shownin FIG. 24.

In addition to batteries, or rechargeable batteries to suitably powerthe USCD as described above, a motor generator system may be alsoprovided in several embodiments of the USCD shown in FIG. 24 that isgenerally designated with the numeral 832 (which comprises equivalentindividual elements such as elements 264, 266, 268, 270, and 272 of themud-motor generator system in FIG. 7). Fluids flowing through the motorgenerator are used to generate power in analogy with the mud-motorgenerator system described in FIG. 7. These fluids are often productionfluids under high pressure that are in the process of flowing to thesurface. In low pressure reservoirs, fluids pumped to the surface mayalso similarly impart energy to the USCD. Therefore, even after the USCDhas been disconnected from the Retrieval Sub, it may still communicateto the Smart Shuttle and/or to the surface by using power from the motorgenerator, any batteries present, and suitable acoustictelecommunication devices, located in the electronics package 830—whichis just one example of this preferred embodiment. Other communicationssystems located in electronics package 830 may be used in yet otherembodiments to communicate between the USCD and the surface. In anotherembodiment, the motor generator may be used to charge rechargeablebatteries in the electronics package 830 if the USCD is disconnectedfrom the Retrieval Sub and its associated Smart Shuttle and wireline.

Measurements performed by the USCD, and the status of various valves,etc. are conveyed to a computer system, such as computer system 556 inFIG. 14. That computer system processes the information, and determinesa sequence of steps in part related to the information that it hasreceived. Accordingly, suitable commands are sent downhole during theprocess of completing a well. Therefore, the USCD in FIG. 24 is aportion of one embodiment of a closed-loop system to complete oil andgas wells.

Communications from the USCD to the computer system may be accomplishedin at least the following manners: (a) if the USCD is attached to itsRetrieval Sub, Smart Shuttle, and wireline, then communications may besent from the USCD over the wireline to the computer system; or (b), ifthe USCD is not attached to its Retrieval Sub, then an acoustic signalor an electromagnetic signal generated within the USCD may be sent tothe Smart Shuttle, and that signal may then be interpreted in the SmartShuttle and suitably electronically relayed to the surface over thewireline; or (c) Smart Cricket Repeaters may be used as described in theU.S. Disclosure Document No. 465344 that is entitled “Smart CricketRepeaters In Drilling Fluids for Wellbore Communications While DrillingOil and Gas Wells” that was previously described above. Similar methodsto (a), (b), and (c) may be used to convey commands and otherinformation sent downhole to the USCD from the computer system on thesurface.

Therefore, it is evident that any one USCD may be installed within anypipe means such as within a casing, a drill pipe, etc. In severalpreferred embodiments related to FIG. 24, any USCD installed within awellbore possesses at least one sensor as means to monitor theproduction of hydrocarbons from the wellbore after completing the oil orgas well. In other preferred embodiments, means to control theproduction of hydrocarbons that are disposed into the wellbore andremain installed in the wellbore after completing the wellbore areprovided such as internal fluid flow control valves 822 and 824 of theUSCD. In yet other preferred embodiments of the USCD in FIG. 24, themeans to monitor the production of hydrocarbons from the wellbore mayalso be used to adjust the means to control the production ofhydrocarbons from the wellbore following the completion of the wellbore,which latter means may be defined herein as an “adjustable means tocontrol the production of hydrocarbons” from within the wellbore. Yetfurther, other embodiments provide for the “remote actuation of theadjustable means to control the production of hydrocarbons”, a termpreviously defined. The remote actuation includes remote actuation fromthe surface of the earth, from an offshore drilling platform, or fromany device installed within the wellbore, such as from the means tomonitor the production of hydrocarbons within the wellbore. In yetfurther embodiments of the invention, a closed-loop system to complete awell for producing hydrocarbons from the earth may also be used for thesecond purpose as a closed-loop system to monitor, control, and maintainproduction from the well.

Closed-Loop Completions of Multilateral Wellbores

As another embodiment of closed-loop well completions, FIG. 25 shows twoUniversal Smart Completion Devices installed in wellbores to make a TAMLLevel 5 Well Completion. This is one category of well completionconfigurations defined by an industry group generally known as the“Technology Advancement of Multilaterals” (“TAML”) group. Thedefinitions of TAML Level well completions appear in at least thefollowing references: (a) the article entitled “MultilateralClassification System with Example Applications” by Alan MacKenzie andCliff Hogg, World Oil, January 1999, pages 55-61, an entire copy ofwhich is incorporated herein by reference; and (b) Section 2, page 19,of the volume entitled “Multilateral Well Technology”, having the authorof “Baker Hughes, Inc.”, that was presented in part by Mr. Randall Cadeof Baker Oil Tools, that was handed-out during a “Short Course” at the“1999 SPE Annual Technical Conference and Exhibition”, October 3-6,Houston, Tex., having the symbol of “SPE International EducationServices” on the front page of the volume, a symbol of the Society ofPetroleum Engineers, which society is located in Richardson, Tex., whichwas previously described above, an entire copy of which is incorporatedherein by reference.

In FIG. 25, the main wellbore 834 has casing 836 installed that has beencemented into place with cement 838. That main wellbore was completedusing Smart Shuttles, Retrieval Subs, and Universal Smart CompletionDevices. A smart bridge plug 840 was set in place by a Smart Shuttle,and perforations 842 and 844 were made in the casing by a Smart Shuttleconveyed perforation gun.

In a preferred embodiment, a first USCD is shown installed in the mainwellbore and it is labeled with numeral 846 in FIG. 25. The first USCDhas its expandable packer in its inflated position, has its casinglocking mechanisms deployed thereby locking the first USCD into place,has its upper and lower valves closed, and has the first and secondfluid control valves set at some nominal level as described below.

Lateral wellbore 848 has casing 850 that is cemented in place withcement 852 to a point defined with numeral 854 and has an open-holesegment 856 in FIG. 25. The lateral wellbore casing 850 joins into themain wellbore casing 836 at the location generally designated withnumeral 857 in FIG. 25. A screen 858 having upper attachment apparatus860 capable of connecting to a Retrieval Sub was deployed into theopen-hole lateral by a Smart Shuttle and its Retrieval Sub. Gravel 861surrounds the screen 858 as is typically installed in certaincompletions. A second USCD is installed within the cased section of thelateral wellbore and it is labeled with numeral 862. The second USCD hasits expandable packer in its inflated position, has its casing lockingmechanisms deployed thereby locking the first USCD into place, has itsupper and lower valves closed, and has the first and second fluidcontrol valves set at some nominal level as described below.

As shown in FIG. 24, the particular embodiment of the Smart Shuttle andRetrieval Sub that deployed the various elements into the wellbore isthe “coiled tubing with wireline Smart Shuttle” abbreviated “CTWWSS”,previously generally designated as element 792 in relation to FIG. 23,which is generally designated with numeral 864 in FIG. 25. Otherpreferred embodiments of the CTWWSS may have suitable flex jointsinstalled along its length so that the radius of curvature of the lengthof the tool can match what is required to complete the well, although nosuch flex joints are explicitly shown in FIG. 25. For example, such aflex joint designated by numeral 865 (not shown) may be installed in theCTWWSS between elements 684 and 685 in FIG. 23, however no such flexjoint having numeral 865 is shown in FIG. 23, nor is it shown in FIG.25, solely for the purposes of simplicity (although numeral 865 isreserved for this purpose in the event that future elaborations on this,and related, preferred embodiments are provided at a later time). Fromthis disclosure, any Smart Shuttle and Retrieval Sub having at least oneflex joint is yet another embodiment of this invention. Further, theCTWWSS has suitable measurement apparatus used in the industry such asMWD sensors, mechanical diverters, orientational apparatus, etc., tolocate the position of the entry to the cased lateral wellbore atlocation 857, but that apparatus is not shown in FIG. 25 for thepurposes of simplicity only.

Commingled production to the surface is perfectly acceptable for manyapplications provided that the production rates from the main wellboreand the lateral are acceptable and cause positive flow rates out of eachportion of the geological formation produced. There are many ways tomonitor commingled production.

A first way to monitor commingled production is as follows. Open theupper and lower valves in the first USCD, measure the flow rates, andsend this information acoustically to the “CTWWSS” for relay to thesurface. Then close these two valves. Then, open the upper and lowervalves in the second USCD, measure the flow rates, and send thisinformation acoustically to the CTWWSS to relay to the surface. Then,suitably adjust the first and second fluid control valves within eitherthe first or second USCD to achieve the proper flow rates. Then, removethe CTWWSS, and replace with a “pump-down single-zone packer apparatus”of the type shown in FIG. 17. Here, of course, there is commingledproduction to the surface from perhaps several zones.

A second way is to actually sample the flow rates separately from thefirst USCD and from the second USCD. Please note that with expandablepacker 866 of the CTWWSS in FIG. 25 expanded to form a seal on theinside of the casing, that any flow through the first USCD will bedirected towards the surface. The Progressive Cavity Pump can be used toassist this flow, or valves 700 and 702 shown in FIG. 23 can be openedinstead. The flow rate through the first USCD can the be adjusted bycommunications provided from the CTWWSS. Similarly, the flow rate can besampled and adjusted through the second USCD by communications providedfrom the CTWWSS.

Third, the flow rates through the first and second USCD can becontrolled from the surface, and suitable determinations made of therespective flow rates. There are many alternative preferred embodimentsof this invention.

It should be noted that the Progressive Cavity Pump can be used toassist production, but in several preferred embodiments, it helps tohave the CTWWSS suitably anchored in place. If the Retrieval Sub of theCTWWSS engages the first USCD, and if the first USCD is locked in place,the CTWWSS will also be locked in place. Similar comments apply to thesecond USCD. Alternatively, the Retrieval Sub of the CTWWSS can befitted with a separate smart casing lock to be conveyed downhole thatwill lock the CTWWSS in place. Of course, production would need tobypass the casing lock, but there are many suitable designs for such asmart casing lock.

In the various preferred embodiments of the invention, measurementsperformed by the first and second USCD, and the status of variousvalves, etc. are conveyed to a computer system, such as computer system556 in FIG. 14. That computer system processes the information, anddetermines a sequence of steps in part related to the information thatit has received from remote sensors located downhole. Accordingly,suitable commands are sent downhole to optimize the steps to completethe wellbore.

Therefore, the first and second USCD's in FIG. 25 are a portion of aclosed-loop system to complete oil and gas wells.

It should also be evident from the previous description how SmartShuttles, Retrieval Subs, Smart Completion Devices, Universal SmartCompletion Devices, and the associated computer system, or computersystems, communications systems, and downhole and uphole sensors, may beused to complete TAML Level 1, 2, 3, 4, 6, and 6s well completions.

Following the initial completion of the multilateral well a first timethat is shown in FIG. 25, it may be necessary to recomplete the well asecond time using apparatus and procedures already described herein. Anexample of such a recompletion might call for plugging the perforations842 and 844, re-perforating the well at different vertical positions,and recompleting the well. It is evident from the above description howthis may be accomplished. As another example, the screen 858 may becomeclogged in time, and it may be necessary to replace that screen. It isalso evident from the above description how this may be accomplished.There are many variations on the invention to recomplete wells. However,a closed-loop system to complete and oil and gas well a first time canbe used a second time to recomplete the well. Therefore, recompletingthe wellbore in FIG. 25 is a minor variation of the invention.According, a closed-loop system to recomplete an oil and gas well ispreferred embodiment of this invention.

The “coiled tubing with wireline Smart Shuttle” abbreviated “CTWWSS” asgenerally designated as numeral 864 in FIG. 25 is an example of “aconveyance means”.

Closed-Loop Systems and Automated Systems in Relation to FIGS. 23, 24and 25

Accordingly, it is now evident that the disclosure related to FIGS. 23,24 and 25 describe an automated well completion system for producinghydrocarbons from a wellbore in the earth that is substantially underthe control of a computer system that executes a sequence of programmedsteps.

Further, disclosure related to FIGS. 23, 24, and 25 describe aclosed-loop system to complete a well for producing hydrocarbons fromthe earth.

Yet further, disclosure related to FIGS. 23, 24 and 25 provide a methodof completing a wellbore to produce hydrocarbons from the earth that issubstantially under the control of an automated computer system thatexecutes a sequence of programmed steps.

And finally, disclosure related to FIGS. 23, 24 and 25 provide a methodto complete a wellbore to produce hydrocarbons from the earth that issubstantially under the control of a closed-loop automated system thatexecutes a sequence of programmed steps, whereby the steps depend uponinformation obtained from at least one sensor located within thewellbore, and whereby the steps are executed during one significantportion of the well completion process.

In relation to FIGS. 23, 24, and 25, and in further reference to FIGS.1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 17, 17A, 18, 18A, 19, 20, 21, and 22, itis evident that after completing the wellbore, the wellbore is comprisedof at least a borehole in a geological formation that surrounds a pipelocated within the borehole, and this pipe may be any one of thefollowing: a metallic pipe; a casing string; a casing string with anyretrievable drill bit removed from the wellbore; a steel pipe; a drillstring; a drill string possessing a drill bit that remains attached tothe end of the drill string after completing the wellbore; a drillstring with any retrievable drill bit removed from the wellbore; acoiled tubing; a coiled tubing possessing a mud-motor drilling apparatusthat remains attached to the coiled tubing after completing thewellbore; or a liner.

In view of the fact that any USCD may have downhole sensors and downholemonitors, it is evident that disclosure related to FIGS. 23, 24, and 25describe well completion methods wherein at least one sensor remains inthe wellbore as means to monitor the production of hydrocarbons from thewellbore after completing the wellbore.

In view of the fact that any USCD may have downhole adjustable means tocontrol production, it is evident that disclosure related to FIGS. 23,24 and 25 describe well completion methods wherein adjustable means tocontrol the production of hydrocarbons are disposed into the wellboreand remain installed in the wellbore after completing the wellbore.

In view of the fact that the USCD may further have suitable monitoringmeans, it is evident that disclosure related to FIGS. 23, 24, and 25describe well completion methods wherein the means to monitor theproduction of hydrocarbons from the wellbore is used to adjust the meansto control the production of hydrocarbons from the wellbore.

In view of the disclosure particularly related to FIG. 25, it is evidentthat disclosure related to FIGS. 23, 24, and 25 describe a closed-loopsystem to complete a well for producing hydrocarbons from the earth,whereby following the completion of the well, the closed-loop system isalso used to monitor, control, and maintain production from thecompleted well.

Closed-Loop Subsea Systems to Complete Oil and Gas Wells

FIG. 26 shows, in diagrammatic form, a closed-loop subsea completionsystem. Subsea tree 868 is located on the ocean floor 870 and it isattached to casing 872 that is installed in wellbore 873 with cement874. The subsea tree has at least one hydraulically actuated ram 875 toprevent blowouts and it has top mating flange 876. The Subsea CompletionModule 878, abbreviated as “SCM”, has a wall 880 so that the pressuremay be controlled inside the SCM at location 882, for example. The SCMhas a bottom mating flange 883 that suitably engages the top matingflange of the subsea tree. Attached to the SCM bottom mating flange ispipe 884 that has hydraulic ram 886 to control blowouts and for otherpurposes.

The SCM in FIG. 26 may be used, and deployed, as if it were a simple“diving bell” by hook support 888. In one embodiment, the SCM is loweredthrough a large hole, or bay, in the bottom of a suitably designedsurface vessel, although that surface vessel is not shown in FIG. 26solely for the purposes of brevity. Such a surface vessel has a suitablecrane with drum having cable that is suitably attached to the hooksupport, although again, that crane is not shown in FIG. 26 solely forthe purposes of brevity. Known art in the industry may be used to designand build a suitable surface vessel. Similarly, and in differentembodiments, the SCM may also be deployed from a drilling platform, adrillship, a semisubmersible, a submarine, a remotely operated vehicle(ROV), or from any ocean going vessel or ocean going means.

When the SCM is in place on the subsea tree, umbilical 890 is connectedto the surface vessel, or instead to a platform, drillship,semisubmersible, or other support vessel on the surface as may bedesirable. Electrical power, control signals, measurements, etc. aresent to and from the surface through the umbilical. It should be notedthat for completeness, in various embodiments, the umbilical can alsoprovide hydraulic controls, and fluids, etc., but solely for thepurposes of simplicity, those features are not explicitly shown in FIG.26.

Umbilical 890 feeds through the wall of the SCM through the pressurefeedthrough 892. The signals to and from the umbilical proceed alongwire bundles 894 to the computer and electronics system 896. Computerand electronics system 896 controls the wireline drum 898 havingwireline 900. Signals from the computer and electronics system 896 aresent via wire bundle 902 to the slip-ring 904 as is typical in thewireline industry. The wireline proceeds to overhead sheave 906.Suspended on the wireline are cablehead 908, Smart Shuttle 910, andRetrieval Sub 912. Various Smart Completion Devices are figurativelyshown as elements 916, 918, and 920 on first automated rack 921. Forexample, any of these elements can be one or more Universal SmartCompletion Devices as shown in FIGS. 24 and 25. Second automated rack922 holds more Smart Completion devices including a Casing Saw 924,Smart Wiper Plug 926, and Smart Perforation Gun 928.

The automated racks are under the control of the computer andelectronics system 896, which in turn, may receive commands from asurface computer, and/or a computer onshore, which together comprise anentire distributed computer system. Upon suitable computer commands, theautomated racks position the Smart Completion Devices in suitableorientation so that they may be grasped by the Retrieval Sub duringsequential completion steps of the wellbore. Various sensors in theSmart Shuttles provide for the closed-loop control of the automatedsystem to complete oil and gas wells shown in FIG. 26. Universal SmartCompletion Devices or other Smart Completion Devices having sensors alsoprovide for the closed-loop control of the automated system to completeoil and gas wells shown in FIG. 26. There are many variations of theembodiment shown in FIG. 26 that provide for the closed-loop control ofthe automated completion system.

It should be noted that it is not necessary to have any human presenceor operation in the SCM, although it is possible. Without humanpresence, then the pressure within the SCM can be raised to typicalpressures available at the wellhead so that entering and leaving thewell head does not necessarily require lubricators, etc. of the typealready described in relations to FIGS. 8 and 17.

To keep excessive weight off the subsea tree, the weight of the SCM inFIG. 26 is substantially supported by jack-up devices in contact withthe ocean floor. First jack-up support is generally designated bynumeral 930 in FIG. 26, and it has first jack-up foot 932 in contactwith the ocean floor and first piston apparatus 934 attached to thebottom of the SCM. Typical art in the industry is used to construct andoperate the jack-up apparatus. Second jack-up support is generallydesignated by numeral 936 in FIG. 26, and it has second jack-up foot 938in contact with the ocean floor and second piston apparatus 940 attachedto the bottom of the SCM. Not shown in FIG. 26 is third jack-up supportthat is numeral 942, and third jack-up foot 944, and third pistonapparatus 946 attached to the bottom of the SCM.

The alignment apparatus in FIG. 26 used to align the SCM with the subseatree is not shown for the purposes of simplicity only. Any alignmentmeans located on the SCM is designated here as element 948, and anyalignment means located on, or near, the subsea tree is designatedherein as element 950, although these elements are not shown in FIG. 26solely for the purposes of brevity. These alignment means in severalembodiments are completely automatic, in that no commands from thesurface are necessary for the alignment means to properly guide the SCMinto place over the subsea tree. Buoyancy controls 952 within the SCMare not shown in FIG. 26 for brevity.

Accordingly, FIG. 26 shows an automated well completion system forproducing hydrocarbons from a wellbore in the earth that issubstantially under the control of a computer system that executes asequence of programmed steps. FIG. 26 also shows a closed-loop system tocomplete a well for producing hydrocarbons from the earth.

The embodiment of a subsea completion system shown in FIG. 26 is theSubsea Completion Module 878. However, the SCM may itself have its ownthrusters and controls. Therefore, in several preferred embodiments, theSCM is in reality itself a remotely operated vehicle (“ROV”). In severalembodiments, the automatic alignment means are used to guide the ROVinto place over the subsea tree. Not shown in FIG. 26 solely for thepurposes of simplicity are suitable ROV thrusters 954 and suitable ROVthruster controls 956. In other embodiments, separate remotely operatedvehicles, or ROV's, or submarines, are be used to guide the SCM in FIG.26 into place over the subsea tree. Using other ROV's operated remotelyfrom an offshore drilling platform to help guide the SCM into place overthe subsea tree is yet another embodiment of the invention.

FIG. 26 shows a wireline within the SCM. However, a separate coiledtubing apparatus can be similarly be added within the SCM as anotherembodiment of the invention. That coiled tubing apparatus is numeral 958in FIG. 26 that is not shown solely for the purposes of brevity.Further, in another preferred embodiment, this coiled tubing apparatuscan be fitted with a mud-motor assembly 960, also not shown in FIG. 26,that may be used to drill holes with a mud-motor drilling apparatus ofthe types previously described herein. In an embodiment, sea water isused in part for the drilling fluid, and it is obtained through waterintake port 962, also not shown in FIG. 26. Any drilling cuttings andthe like will be exhausted into the ocean through drilling cuttingexhaust port 964 in the SCM, but that is not shown in FIG. 26 for thepurposes of simplicity. Yet further, the mount for the coiled tubingapparatus can also be fitted to rotate about its base further enhancingthe efficiency of the coiled tubing drilling apparatus.

Accordingly, it is now evident that the disclosure related to FIG. 26describes an automated well completion system for producing hydrocarbonsfrom a wellbore in the earth that is substantially under the control ofa computer system that executes a sequence of programmed steps.

Further, disclosure related to FIG. 26 describes a closed-loop system tocomplete a well for producing hydrocarbons from the earth.

Yet further, disclosure related to FIG. 26 provides a method ofcompleting a wellbore to produce hydrocarbons from the earth that issubstantially under the control of an automated computer system thatexecutes a sequence of programmed steps.

And finally, disclosure related to FIG. 26 provides a method to completea wellbore to produce hydrocarbons from the earth that is substantiallyunder the control of a closed-loop automated system that executes asequence of programmed steps, whereby the steps depend upon informationobtained from at least one sensor located within the wellbore, andwhereby the steps are executed during one significant portion of thewell completion process.

Closed-Loop Tractor Conveyance System

FIG. 27 shows another well conveyance means. FIG. 27 was originallyfiled in the U.S.P.T.O. on the date of Oct. 2, 2000 as a portion of U.S.Disclosure Document 480550. Wireline 966 possesses one or moreelectrical conductors. In several preferred embodiments, wireline 966possesses one or more high power electrical conductors. Wireline 966also provides means for two-way data communications as may be providedby one or more electrical conductors or by one or more optical fibers.Wireline 966 also provides means for two-way data communications as maybe provided with two or more electrical conductors or by one or moreoptical fibers. This wireline 966 provides first and secondcommunications means. The wireline may conduct large amounts of powerdownhole and may have any number of current carrying conductors, and anynumber of signal conductors, or may have one or more optical fibers. Inthe case of an optical fiber, the first and second communications meansare combined into a single bidirectional communications system, or intoa single communication system means. Cablehead 968 connects the wireline966 to tractor conveyor 970. The tractor conveyor has at least onefriction wheel 972 which engages the interior of pipe 974. The tractorconveyor has four friction wheels as shown in FIG. 27. This frictionwheel is analogous to element 546 in FIG. 13. Quick change collarassembly 976 connects the tractor conveyor to the Retrieval Sub 978.

The tractor conveyor 970 with its Retrieval Sub 976 installed in FIG. 27is an example of a “tractor conveyance means”, a “tractor deployer”, ora “downhole tractor deployment device”. Electrical energy delivered viathe wireline to the tractor conveyor is used to drive electrical motorsand/or electro-hydraulic systems to provide rotational energy to thefriction wheels. That rotational energy causes the tractor conveyor tomove within the well.

The tractor conveyance means in FIG. 27 provides similar operationalfeatures as different embodiments previously described heretofore asSmart Shuttles. The instrumentation described in FIG. 14 is used toprovide the automated control of the tractor conveyance means. Thetractor conveyance means may have any one or more of the featuresdescribed in the above “List of Smart Shuttle Features” under items (a),(b), . . . (z), (aa), and (ab). Any of the completions devices listedunder the section entitled “List of Smart Completion Devices” may beattached to the Retrieval Sub. Here, for the tractor conveyance means,the Retrieval Sub performs analogous functions as previously describedfor the Smart Shuttle in the above “List of Retrieval Sub Features”.

By analogy with the Smart Shuttle, the tractor conveyance means may beused as a portion of an “automated well servicing system” for producinghydrocarbons from a wellbore in the earth. Herein, this automated systemis called the “tractor conveyance system” or the “automated tractorconveyance system”. The tractor conveyance means is substantially underthe control of a computer system that executes a sequence of programmedsteps that has at least one computer system located on the surface ofthe earth and has means to convey at least one completion device intothe wellbore under the automated control of the computer system. Theautomated system has at least one sensor means located within thetractor conveyance means, has first communications means that providescommands from the computer system to the tractor conveyance means, hassecond communications means that provides information from the sensormeans to the computer system, where the execution of the programmedsteps of the computer system to control the tractor conveyance meanstakes into account information received from the sensor means tooptimize the steps executed by the computer system to service the well.

The Retrieval Sub can be attached to a number of the devices shown inFIG. 28. Those devices include any commercial tool or device 980; anylogging tool 982; any torque reaction centralizer 984; any scraper 986;an perforating tool 988; any flow meter 990; any Downhole Rig withrotary bit 992; any Universal Completion Device 994; any straddle packer996; any injection tool 998; any oil/gas separator 1000; any flow linecleaning tool 1002; any casing expanding tool 1004; any plug 1006; anyvalve 1008; and any locking mechanism 1010. These different tools areeither defined in applicant's applications or are tools used in the oiland gas industry. The point is that any of these devices can be attachedto the Retrieval Sub of the Cased Hole Smart Shuttle 1012 or to theRetrieval Sub of the Open Hole Smart Shuttle 1014. These devices maysimilarly be attached to the Retrieval Sub of the tractor conveyancemeans. Each such device in this paragraph may be called a “completiondevice” and collectively, these may be referenced as “completiondevices”.

These devices specified in the previous paragraph may be used for avariety of different purposes in the oil and gas industry. Many of thosetools can be used to serve wells. Please refer to FIG. 29 that shows adiagrammatic representation of functions that may be performed with theSmart Shuttle or the Well Locomotive. FIG. 29 shows that the SmartShuttle or the Well Locomotive shown diagrammatically as element 1016may be used for the purposes of completion 1018 (ie., to performcompletion services on a well); production & maintenance 1020 (ie., toperform production and maintenance services on a well); enhancedrecovery 1022 (ie., to perform enhanced recovery services on a well);and for drilling 1024. Under completion functions, or “completionservices”, the Smart Shuttle and Well Locomotive may be used for thecompletion of extended reach lateral wells 1026; for logging andperforating 1028; for stimulation and fluid services 1030; may be usedto install the Universal Completion Devices 1032; and may be used toinstall completion hardware such as plugs, valves, gages, etc. 1034.Under production and maintenance functions, or “production andmaintenance services”, the Smart Shuttle and Well Locomotive may be usedfor flow assurance services 1036; for maintenance and repair 1038; forworkovers, that include logging, perforating, etc., 1040; and forreservoir monitoring and control 1042. Under enhanced recoveryfunctions, or “enhanced recovery services”, the Smart Shuttle and WellLocomotive may be used for recompletions, well extensions, and laterals1044; to install downhole separators 1046; to perform artificial lift1048; to facilitate downhole injection 1050; and for fluid services1052. Under drilling functions, or under “drilling services”, the SmartShuttle and the Well Locomotive may be used for casing drilling purposes1054; for liner drainhole drilling purposes 1056; for coiled tubingdrilling 1058; and for extended reach lateral drilling 1060. Extensivedetails are provided in about each of these functions in the relatedU.S. Disclosure Documents and in the related Provisional PatentApplications cited above.

Any one or more of the functions provided in the previous paragraph iscalled a “well service”. Two or more of such functions are called “wellservices”. The execution of the programmed steps of the automatedcomputer system to control the tractor conveyance means takes intoaccount information received from the sensor means within the tractorconveyance means to optimize the steps executed by the computer systemto service the well.

The tractor conveyance means may be used to perform analogous servicesas enumerated above in FIG. 29 with the Smart Shuttle and the WellLocomotive. A tractor conveyance means includes downhole devices thatuse electrical energy to turn at least one wheel, or cam, or spiralgear, or any other means that generates direct friction against the pipeto cause the tractor conveyance means to move within the pipe.

Accordingly, FIG. 27 describes an automated well servicing system forproducing hydrocarbons from a wellbore in the earth that issubstantially under the control of a computer system that executes asequence of programmed steps that has at least one computer systemlocated on the surface of the earth, has at least one tractor conveyancemeans to convey at least one completion device into said wellbore underthe automated control of the computer system, has at least one sensormeans located within the tractor conveyance means, has firstcommunications means that provides commands from the computer system tothe tractor conveyance means, has second communications means thatprovides information from the sensor means to the computer system, wherethe execution of the programmed steps of the computer system to controlthe tractor conveyance means takes into account information receivedfrom the sensor means to optimize the steps executed by the computersystem to service the well.

FIG. 30 shows another well conveyance means. FIG. 30 was originallyfiled in the U.S.P.T.O. on the date of Oct. 2, 2000 as a portion of U.S.Disclosure Document 480550. Element is 1062 is an umbilical. In onepreferred embodiment, the umbilical is fabricated from a compositematerial and possesses one or more high power electrical conductors andmeans for two-way data communications. Such umbilicals may bemanufactured on a custom basis by ABB Ltd. of Zurich, Switzerland. Aspecific division of ABB Ltd. that is ABB Offshore Systems Inc. which isbased in Houston, Tex., can manufacture the umbilicals. A specificexample of a composite is a material made from carbon fiber-epoxy resin.Umbilical terminator 1064 connects the high power umbilical 1062 totractor conveyor 970. The other elements are the same as in FIG. 27. Thetractor conveyor has at least one friction wheel which engages theinterior of pipe 974. This friction wheel is analogous to element 546 inFIG. 13. Quick change collar assembly 974 connects the tractor conveyorto the Retrieval Sub 976. The tractor conveyor 970 and the Retrieval Sub976 are an example of a “conveyance means”. The conveyance means in FIG.30 provides similar operational features as different embodimentspreviously described as Smart Shuttles.

Electrical energy delivered via the high power umbilical to the tractorconveyor is used to drive electrical motors and/or electro-hydraulicsystems to provide rotational energy to the friction wheels. Thatrotational energy causes the tractor conveyor to move within the well.

The umbilical is mounted on an umbilical drum analogous to wireline drum578 shown in FIG. 14. The motion of the tractor conveyor is monitoredwith computer system analogous to computer system 556 in FIG. 14 whichprovides the closed-loop automated control of the tractor conveyancemeans during well servicing operations.

The above has described one embodiment of the umbilical 1062 in FIG. 30.In different preferred embodiments, the umbilical 1062 may be selectedto be any one of the following: (a) a coiled tubing, or a coiled tubingthat encapsulates electrical conductors; (b) a coiled tubing made fromsteel that encapsulates one or more electrical conductors within theinterior of the steel coiled tubing; (c) a steel coiled tubing thatencapsulates a wireline that is disposed within the interior of thecoiled tubing that in turns possesses one or more electrical conductors;(d) a steel coiled tubing that encapsulates electrical conductorsprotected by any sheath, or other protection means; (e) tubing made fromcomposite material, or a composite coiled tubing that encapsulates oneor more electrical conductors that are disposed within the interior ofthe coiled tubing; (f) a composite coiled tubing that encapsulates awireline that is disposed within the interior of the coiled tubing thatin turns possesses electrical conductors; (g) a composite coiled tubingthat possesses one or more electrical conductors that are disposedwithin the walls of said coiled tubing made from composite material; (h)a composite coiled tubing that encapsulates electrical conductorsprotected by any sheath or other protection means; (i) any tubularstructure including one or more tubes, one within another, at least oneof which has an electrical conductor disposed within regions between thewalls of the tubes or within the walls of the tubes; and (j) any“tubular means possessing at least one electrical conductor” thatincludes (a), (b), (c), (d), (e), (f), (g), (h), and (i), and in thisparagraph. Element 1062 having any of the above attributes of (a), (b),(c), (d), (e), (f), (g), (h), (i), and (j) may also be called an“umbilical means having at least one electrical conductor”. Anyumbilical means may be intentionally designed to be neutrally buoyant inany fluids within a well. Accordingly, there are many different types ofumbilicals that correspond to element 1062 in FIG. 30. Element 30 inFIG. 30 is an “umbilical means”.

FIG. 31 shows a cross section of an embodiment of umbilical 1062 in FIG.30. FIG. 31 was originally filed in the U.S.P.T.O. on the date of Oct.2, 2000 as a portion of U.S. Disclosure Document 480550. In oneembodiment of FIG. 31, at least one insulated electrical conductor 1066is encapsulated by first composite material 1068. (In other embodiments,the wire is not insulated.) An optical fiber 1070 for two-way datacommunications is also encapsulated by first composite material 1068.First composite material 980 surrounds second composite material 1072.(Alternatively, other separate electrical conductors can be encapsulatedwithin the composite material 1068 for data communications purposes orfor other purposes.)

The first composite material is chosen for its good strength, durabilityagainst abrasion in the well, and perhaps for its electrical insulationproperties. In one embodiment of FIG. 31, the second composite materialis chosen so with a particular specific gravity such that the overallumbilical is neutrally buoyant in typical well fluids (in 12 lb pergallon mud, for example, or in salt water, as another example).Syntactic foam materials having silica microspheres as provided by theCumming Corporation (www.emersoncumming.com) for such purposes. Thedetails on pressure balanced silica microspheres in syntactic foam maybe reviewed in Attachment 28 to the Provisional Patent Applicationmailed to the USPTO under a Certificate of Express Mailing on the dateof Jun. 3, 2002, an entire copy of which is incorporated herein byreference.

In yet another embodiment of FIG. 31, the above composite materials isleft out of the interior, and the interior forms a tube through whichfluids can be conducted downhole. In this case, element 1072 on FIG. 31would be replaced with element 1074 which would point to a void (notshown for the purposes of brevity). In this particular embodiment, thefirst composite material would be also be chosen to be as neurallybuoyant as possible.

Therefore, different embodiments of umbilicals provide electric powerdownhole, bidirectional communications, which are neutrally buoyant inwell fluids. In addition, yet other umbilicals also provide the abilityto conduct fluids to and from the borehole. Umbilicals handling wellfluids are useful with a number of well services including the use withstraddle packers, injection tools, oil gas separators, flow linecleaning tools, valves, etc.

FIG. 32 shows yet another neutrally buoyant composite umbilical in 12 lbper gallon mud. Outer spoolable composite tubing 1076 is 1.75 inchesO.D. and 1.25 inches I.D. having a specific gravity of 1.50. Three each0.355 inch O.D. insulated No. 4 AWG Wires 1078, 1080 and 1082 aredisposed within the I.D. of the spoolable composite tubing. Opticalfiber 1084 is also disposed within the spoolable composite tubing. Theremaining available volume within the spoolable composite is then filledwith pressure balanced silica microspheres in syntactic foam that has aspecific gravity of 0.60. A simple calculation shows that this umbilicalin 12 lbs/gallon mud weighs −50 lbs for every 1,00 feet. Assuming acoefficient of friction of 0.2, at 20 miles the umbilical could pullback with a frictional force of 1,056 lbs. So, this umbilical issubstantially neutrally buoyant (or simply “neutrally buoyant” asdefined below). The insulated wire is rated at 14,000 volts. Thisparticular wire is Part Number FEP4FLEXSC available through Allied Wire& Cable located in Bridgeport, Pa.

FIG. 33 shows how three phase power of 160 horsepower (119 kilowatts)can be delivered through the conductors in FIG. 32 to distances of 20miles. Two “legs” of the three phase delta circuit are shown in FIG. 33as wires “A” and “B” (wire “C” of the three phase delta circuit is notshown for simplicity). The resistances of a length of 20 miles of thewire is simulated with resistors having the magnitude of resistance inohms of “R1”. These two resistors are respectively labeled as elements1088 and 1090. The load at the end of the umbilical is simulated with adownhole electric motor 1092 requiring 2,500 volts 0-peak at 45 amps0-peak between any two wires of the three phase wiring system operatingat 60 Hz. A variable voltage supply on the surface 1094 is continuallyadjusted to provide the required voltage at the downhole motor.Typically, the variable voltage supply on the surface 1094 will operateat 6,182 volts 0-peak and will provide 45 amps 0-peak between any twolegs of the three phase circuit. The point of this is that using such avariably voltage supply and reasonably gauge wiring, it is possible toactually deliver 160 horsepower (119 kilowatts) at a distance of 20miles. The density of the pressure balanced silica microspheres insyntactic foam is chosen to make this umbilical neutrally buoyant in 12lb per gallon mud. Detailed calculations of the power calculations areprovided in “Attachment C” to Provisional Patent Application No.60/353,457, an entire copy of which is incorporated herein by reference.The details on the pressure balanced silica microspheres in syntacticfoam can referred to in Attachment 28 to the Provisional PatentApplication mailed to the USPTO under a Certificate of Express Mail onthe date of Jun. 3, 2002, an entire copy of which is incorporated hereinby reference. As stated above, such materials are available from theCumming Corporation (www.emersoncumming.com).

The voltage to the downhole motor 1092 is controlled by a feedbacksystem shown in FIG. 34. Wires A and B, and downhole motor 1092 havebeen identified in FIG. 33. The voltage across two legs of the threephase motor is measured with voltmeter 1096, and this voltage isdigitized with related instrumentation (not shown for the purposes ofsimplicity), and the related voltage information is forwarded uphole bylight pulses sent through optical fiber 1098. That information isreceived by computer system 1100 and related electronics (not shown forthe purposes of simplicity). The output of the computer system adjuststhe voltage and frequency by surface control electronics 1102. The poweris supplied by generator 1104. So, the correct voltage is provided tothe downhole motor by this very practical feedback system. FIG. 33 isAttachment (h) to Provisional Patent Application No. 60/367,638, anentire copy of which is incorporated herein by reference.

FIG. 35 shows an umbilical that is substantially neutrally buoyant in 12lb per gallon mud. It has an OD of 6.00 inches and an ID of 4.5 inches.The ID forms a pipe through which fluids may be sent to and fromdownhole. Put another way, the ID forms a provides a conduit for fluids.For example, drilling mud may be sent downhole through the 4.5 inch ID.The ID of this pipe is also called the interior of this pipe.

The umbilical in FIG. 35 has a 4.5 inch ID pipe labeled with element1106 having a wall thickness of 0.25 inches that is made from acarbon-based composite material having a specific gravity of 1.5. Alsoshown in FIG. 35 is a 6.0 inch OD pipe labeled with element 1108 havingwall thickness of 0.25 inches that is made from a carbon-based compositematerial having a specific gravity of 1.5. In the asymmetric volume 1110between the two pipes are insulated electric wires A, B, C, D, E, and F.Also shown is fiber optic cable 1112. The asymmetric volume 1110 betweenthe two pipes that contains wires A, B, C, D, E, and F, and fiber opticcable 1112, is otherwise filled with silica microspheres that areembedded in syntactic foam material called herein a “filler material”.This “filler material” is described above. The specific gravity of the“filler material”0.825 in this example. In 12 gallon mud, the upwardbuoyant force is plus 5.9 lbs per 1000 feet of this umbilical. Assuminga coefficient of friction of 0.2, the total frictional “pull-back” on 20miles of this umbilical is only 124 lbs. This “pull-back” does notinclude any differential fluid drag forces. This umbilical was chosen tohave an extreme length which shows that the essentially neutrallybuoyant umbilical overcomes most friction problems associated withumbilicals disposed in wells. The ID of pipe 1106 forms a conduit forfluids. Therefore, the apparatus in FIG. 35 shows an umbilical thatprovides a conduit for fluids.

Wires A, B, C, D, E, and F are 0.355 inches O.D. insulated No. 4 AWGWire. The insulation is rated at 14,000 volts. Wires A, B, and Ccomprises the first independent thee phase delta circuit. Wires A and Bare shown in FIG. 33. Wires D, E, and F comprise the second independentthree phase delta circuit. Each separate circuit is capable of providing160 horsepower (119 kilowatts) at 20 miles at the temperature of 150degrees C. So, combined, the umbilical can deliver a total of 320horsepower (238 kilowatts) at 20 miles.

The first independent circuit provides 2,500 volts 0-peak to a load, amotor in this preferred embodiment, at 20 miles between wires A, B, andC respectively, and the motor may draw up to 45 amps 0-peak between anypairs of wires, A-B, B-C, or C-A. The second independent circuit alsoprovides 2,500 volts 0-peak to a motor at 20 miles between wires D, E,and F respectively, and the motor may draw up to 45 amps 0-peak from anywire D,E, and F. Such voltages and currents are necessary for two seriesoperated REDA 4 Pole Motors, each rated for 80 Horsepower. REDA is amanufacturer located in Bartlesville, Okla.

In different preferred embodiments of the invention, umbilicalsdescribed in this section can substitute for wireline 302 in FIG. 8;wireline 302 in FIG. 9; wireline 302 in FIG. 10; wireline 580 in FIG.14; coiled tubing 656 in FIG. 17; coiled tubing 656 in FIG. 17A;wireline 690 in FIG. 19; wireline 762 in FIG. 21; coiled tubing 768 inFIG. 22; coiled tubing 772 that has wireline 774 installed within it asshown in FIG. 23; and wireline 900 in FIG. 26.

The above umbilicals have stated calculations pertaining to lengths of20 miles. However, the umbilicals can be any length from 100's of feetto 20 miles. The extreme distanced of 20 miles was chosen to showneutrally buoyant umbilicals can provide high power and high speed datacommunications at great distances that has heretofore not beenrecognized in the oil and gas industry.

The term “neutrally buoyant” has been used above. Another equivalentterm is “substantially neutrally buoyant”. In one preferred embodiment,the meaning of these terms is that in the presence of the well fluids,that the buoyancy of the umbilical causes the typical friction of theumbilical against the well to be reduced by at least 90% than wouldotherwise be the case.

As stated earlier, the tractor conveyor 970 with its Retrieval Sub 976in FIG. 27 is an example of a “conveyance means”, a “tractor conveyancemeans”, a “tractor deployer”, or a “downhole tractor deployment device”.There are many “well tractors”, or devices related to well tractors, aselection of which are described in the following documents: U.S. Pat.Nos. 6,347,674; 6,345,669; 6,318,470; 6,296,066; 6,273,189; 6,257,332;6,241,031; 6,241,028; 6,225,719; 6,179,058; 6,179,055; 6,173,787;6,089,323; 6,082,461; 5,954,131; 5,794,703; 5,547,314; 5,375,668;5,209,304; 5,184,676; 5,121,694; 5,018,451; 5,040,619; 4,960,173;4,686,653; 4,643,377; 4,624,306; 4,570,709; 4,463,814; 4,243,099;4,192,380; 4,085,808; 4,071,086; 4,031,750; 3,969,950; 3,890,905;3,888,319; 3,827,512; in EP0564500B1; and in WO9806927; WO9521987;WO9318277; and WO9116520; entire copies of which are incorporated hereinby reference. Entire copies of the 39 cited references in this paragraphare incorporated herein by reference. Many of these devices are means tocause or generate movement within wellbores. Such “movement means” maybe attached to a device similar to the Retrieval Sub 976. Devicessimilar to Retrieval Sub 976 are called “retrieval means”. So, movementmeans may be coupled to retrieval means to make a “tractor conveyancemeans”, or tractor deployers, or downhole tractor deployment devices.

In view of the above, preferred embodiments of this invention disclose aclosed-loop system to service a well for producing hydrocarbons from aborehole in the earth having at least one computer system located on thesurface of the earth, which possess at least one conveyance means toconvey at least one completion device into the borehole under theautomated control of the computer system that executes a series ofprogrammed steps, which possess at least one sensor means located withinthe conveyance means, which have first communications means thatprovides commands from the computer system to the conveyance means andpossessing second communications means that provides information fromthe sensor means to the computer system, whereby the execution of theprogrammed steps by the computer system to control the conveyance meanstakes into account information received from the sensor means tooptimize the steps executed by the computer to service the well. Suchsystem is called a “closed-loop tractor conveyance system”. Theclosed-loop system may also be used to monitor and control production ofhydrocarbons from the wellbore.

While the above description contains many specificities, these shouldnot be construed as limitations on the scope of the invention, butrather as exemplification of preferred embodiments thereto. As have beenbriefly described, there are many possible variations. Accordingly, thescope of the invention should be determined not only by the embodimentsillustrated, but by the appended claims and their legal equivalents.

1. An automated well servicing system for producing hydrocarbons from awellbore in the earth that is substantially under the control of acomputer system that executes a sequence of programmed steps comprising:(a) at least one computer system located on the surface of the earth;(b) at least one tractor conveyance means to convey at least onecompletion device into said wellbore under the automated control of saidcomputer system; (c) at least one sensor means located within saidtractor conveyance means; (d) first communications means that providescommands from said computer system to said tractor conveyance means; (e)second communications means that provides information from said sensormeans to said computer system, whereby the execution of the programmedsteps of said computer system to control said tractor conveyance meanstakes into account information received from said sensor means tooptimize the steps executed by the computer system to service the well.2. The apparatus in claim 1 that is used to perform completion serviceson a well.
 3. The apparatus in claim 1 that is used to performproduction and maintenance services on a well.
 4. The apparatus in claim1 that is used to perform enhanced recovery services on a well.
 5. Theapparatus in claim 1, whereby said tractor conveyance means is connectedto said automated well servicing system by a wireline.
 6. The apparatusin claim 5, whereby said wireline provides electrical power to saidtractor conveyance means.
 7. The apparatus in claim 6, whereby saidwireline provides said first and second communications means.
 8. Theapparatus in claim 1, whereby said tractor conveyance means is connectedto said automated well servicing system by an umbilical.
 9. Theapparatus in claim 8, whereby said umbilical is substantially neutrallybuoyant in any well fluids present in the well.
 10. The apparatus inclaim 9, whereby said umbilical provides electrical power to saidtractor conveyance means.
 11. The apparatus in claim 9, whereby saidumbilical provides said first and second communications means.
 12. Theapparatus in claim 11 whereby said first and second communications meansare combined into a single bidirectional communications system means.13. The apparatus in claim 12, whereby said first and secondcommunications means are one optical fiber disposed within theumbilical.
 14. The apparatus in claim 11, whereby said first and secondcommunications means are two or more electrical wires within saidumbilical.
 15. The apparatus in claim 8, whereby said umbilical providesa conduit for fluids.
 16. The apparatus in claim 8 whereby saidumbilical is made from materials that includes at least one compositematerial.
 17. The apparatus in claim 16 whereby said composite materialis a carbon-based composite material.
 18. The apparatus in claim 17whereby said composite material encapsulates a volume containing silicamicrospheres that are embedded in syntactic foam material, whereby saidvolume is used to adjust the buoyancy of the umbilical.
 19. Theapparatus in claim 1, whereby said tractor conveyance means is connectedto said automated well servicing system by an umbilical means.
 20. Theapparatus in claim 19 whereby said umbilical means is a coiled tubing.21. The apparatus in claim 20 whereby said coiled tubing is made fromsteel.
 22. The apparatus in claim 21 whereby one or more electricalconductors are disposed within the interior of said steel coiled tubing.23. The apparatus in claim 21 whereby a wireline is disposed within theinterior of said steel coiled tubing.
 24. The apparatus in claim 20whereby said coiled tubing is made from a composite material.
 25. Theapparatus in claim 24 whereby one or more electrical conductors aredisposed within the interior of said coiled tubing made from compositematerial.
 26. The apparatus in claim 24 whereby one or more electricalconductors are disposed within the walls of said coiled tubing that ismade from said composite material.
 27. The apparatus in claim 24 wherebya wireline is disposed within the interior of the coiled tubing that ismade from said composite material.
 28. The apparatus in claim 1, wherebysaid tractor conveyance means is connected to said automated wellservicing system by any tubular means possessing at least one electricalconductor.
 29. The apparatus in claim 1, whereby said tractor conveyancemeans is connected to said automated well servicing system by anumbilical means having at least one electrical conductor.